4890S11/FICHT-5530494-v2

Study November 2009

A Regulatory Framework for Wind Power in Vietnam

4890S11/FICHT-5530494-v2

Please contact: Institute of Energy

Address: 6 Ton That Tung street, Hanoi, Vietnam

Rev No. Rev-date Contents/amendments Prepared/revised Checked/released

0 1 2

Sarweystraße 3 70191 Stuttgart • Germany Phone: + 49 711 8995-0 Fax: + 49 711 8995-459 www.fichtner.de Please contact: Ole Langniß Extension: 584 E-mail: Ole.Langniss@fichtner.de

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Table of Contents

1. International Regulatory Mechanism 1-1

1.1 Price-based mechanisms 1-1

1.1.1 Feed In Tariff 1-2

Tariff setting 1-2

Stepped tariff designs 1-3

FIT Design Guidelines 1-5

1.1.2 Premium tariff design 1-5

1.1.3 Example: Spain 1-6

1.1.4 Example: China 1-7

1.1.5 Example: India 1-9

1.2 Quantity-based mechanisms 1-10

1.2.1 Quota Model 1-11

Quota Model Design Guidelines 1-11

1.2.2 Example: United Kingdom 1-12

1.3 Tendering Scheme 1-13

1.3.1 Example: Portugal 1-14

Tendering Scheme 1-14

1.4 Conclusion 1-15

1.5 The Choice of Main Instrument considering the Vietnamese Framework Conditions 1-17

National RE goals 1-18

2. Existing Regulatory Mechanism of Vietnam 2-1

3. Project Qualification Criteria 3-1

3.1 Size categories 3-1

3.2 Minimum specific power yield 3-2

3.3 Contribution to provision of power for the electricity supply system 3-3

3.4 Required technical availability 3-4

3.5 Criteria for reviewing technical feasibility 3-5

3.6 Criteria for reviewing economic feasibility 3-5

3.7 Maturity of wind power plants 3-6

3.8 Share of local manufacturing 3-6

3.9 Ownership restrictions 3-7

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3.10 Used vs. new turbines 3-8

3.11 Spatial restriction 3-9

4. Evaluation Criteria for License Applications 4-1

4.1 Investment Law No.59/2005/QH11 4-1

4.2 Decision No: 30/2006/QD-BCN 4-1

4.3 Decree No. 78-2007-ND-CP 4-3

4.4 Potential Barriers 4-5

5. Calculation of the Levelised Electricity Costs 5-1

5.1 Site selection and characterization 5-1

5.2 Selection of reference wind turbines 5-4

5.3 Annual gross electricity production 5-4

5.4 Capacity factor 5-4

5.5 Equivalent full load hours 5-6

5.6 Investment costs 5-6

5.6.1 Wind turbine 5-6

5.6.2 Incidentals 5-8

Foundation 5-9

Grid connection 5-10

5.7 Operation & maintenance costs 5-11

5.7.1 Local cost structure 5-11

Labour costs 5-11

5.7.2 Escalation of O&M costs during technical lifetime 5-12

5.7.3 Weighted average cost of capital 5-13

5.7.4 Levelised O&M costs 5-13

5.8 Wind farm net electricity generation 5-13

5.9 Levelised electricity generation costs 5-13

5.10 Wind energy potential in Vietnam 5-16

5.11 Sensitivity analysis 5-18

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6. Guaranteed Payment Period 6-1

7. Tariff Adjustment 7-1

8. Purchase Obligation 8-1

9. Grid Connection Cost and Obligation 9-1

10. Institutional Framework for Administration of the Feed-In Tariff Scheme 10-1

10.1 Identification of the appropriate implementing institution 10-1

10.1.1 Potential candidates 10-1

10.1.2 Assessment and recommendation 10-6

10.2 Organizational set-up of the implementing institution 10-8

10.2.1 Institutional set-up 10-8

10.2.2 Organizational set-up 10-8

10.2.3 Functions 10-9

10.2.4 Staffing 10-10

10.2.5 Funding and budget 10-10

10.2.6 Cash flow 10-11

10.3 Monitoring, Reporting and Review 10-13

11. Tariff Funding Requirements 11-1

11.1 Additional costs 11-1

12. Sources of Finance 12-1

12.1 Vietnam Environmental Protection Fund (VEPF) 12-1

12.2 Surcharges 12-3

12.3 The Global Environment Facility 12-4

12.3.1 Projects funded in Vietnam 12-4

12.3.2 Project types eligible for GEF funding 12-8

12.3.3 The GEF project cycle 12-8

12.3.4 Summary GEF funds 12-10

12.4 Clean Development Mechanism 12-11

12.4.1 Registration of wind power projects under the normal CDM 12-11

12.4.2 Registration of wind power projects under Program of Activities (PoA) under the CDM 12-12

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12.4.3 Developments of a Post 2012 CDM 12-1

12.5 Conclusion 12-9

13. Carbon Dioxide Mitigation Calculation 13-1

13.1 Clean Development Mechanism (CDM) and the contribution to the development of renewable energy & wind energy in Vietnam 13-1

13.2 Methodology tool 13-2

13.2.1 Identify baseline 13-2

13.2.2 National electricity grid emission factor calculation 13-3

14. References 14-1

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List of Abbreviations CERC Central Electricity Regulatory Commission FIT Feed-In Tariff IPP Independent Power Producer NDRC National Development and Reform Committee NFFO Non Fossil Fuel Obligation NSE Non Sustainable Energy RD Royal Decree RE Renewable Energy RES Renewable Energy sources RES-E Electricity generated from renewable sources RO Renewable Obligation ROC Renewable Obligation Certificate OFGEM Office of Gas and Electricity Markets PPA Power Purchase Agreement TGC Tradable Green Certificate TSO Transmission System Operator

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List of Tables Table 1-1: Advantages and Disadvantaged of a Stepped FIT ............................................1-5 Table 1-2: Advantages and Disadvantages of Premium FIT..............................................1-6 Table 1-3: Advantages and disadvantages of particular support instruments ..................1-16 Table 2-1: Electricity Tariff (VND/kWh)...........................................................................2-5 Table 5-1: Wind categories [World Bank Wind Atlas SE Asia] ........................................5-3 Table 5-2: Reference wind turbines....................................................................................5-4 Table 5-3: Typical Hub Heights .........................................................................................5-7 Table 5-4: Operation and Maintenance costs of a Nordex S70 installation. ....................5-12 Table 5-5: Weighed Average Cost of Capital...................................................................5-13 Table 5-6: LEC calculation for scenario wind project consistent of 20 Nordex S70 .......5-15 Table 5-7: Range of levelised electricity generating costs in the examined sample of wind turbines. ...............................................................................................................5-15 Table 5-8: Wind Energy Potential in Vietnam [World Bank] ..........................................5-16 Table 5-9: Modified Wind Energy Potential [World Bank and Nguyen].........................5-17 Table 6-1: Change of tariff compared to 20 year payment duration ..................................6-1 Table 6-2: Duration of support for wind energy in different countries. (Source: German Federal Ministry for the Environment, Nature Conservation and Nuclear Safety (BMU): http://www.res-legal.eu/...............................................................6-2 Table 7-1: Tariff adaption mechanisms for new installations. Source: German Federal Ministry for the Environment, Nature Conservation and Nuclear Safety (BMU): http://www.res-legal.eu/ and Fraunhofer ISI, Energy Economics Group: Evaluation of different feed-in tariff design options .............................................7-3 Table 10-1: Monitoring and reporting requirements ......................................................10-16 Table 12-1: Specification of electricity sales price according to Decision No. 21/2009/QD-TTg ..............................................................................................................12-3 Table 12-2: Adjustment of electricity sales price according to Decision No. 21/2009/QD-TTg ..............................................................................................................12-3 Table 12-3: Related projects funded under GEF in Vietnam ...........................................12-6 Table 12-4: Related projects funded under GEF in other geographical areas ..................12-7 Table 12-5: GEF Operational Focal Point in Vietnam .....................................................12-9 Table 12-6: Comparison of Program of Activities vs. bundling individual projects. (DEHST07). .....................................................................................................12-15 Table 12-7: Required steps to prove additionality..........................................................12-19 Table 12-8: Assessment of different institutions on the feasibility as managing entity for a Program of Activity. Note: ● poor ● good............................................12-26 Table 13-1: Calculation of Emission Reduction...............................................................13-7 Table 13-2: Resulting average combined margin for CO2 emissions...............................13-7 Table 13-3: Amount of CO2 emission reduction..............................................................13-8

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List of Figures Figure 1-1: Price-based instrument.....................................................................................1-2 Figure 1-2: Flat tariff design [Kle08] .................................................................................1-3 Figure 1-3: Site quality dependent stepped tariff design [Kle08].......................................1-4 Figure 1-4: Capacity dependent stepped tariff design [Kle08]...........................................1-4 Figure 1-5: Capacity-based mechanism............................................................................1-11 Figure 1-6: Applicable Support Instruments ....................................................................1-15 Figure 5-1: Location of the chosen sites [internal sources] ................................................5-3 Figure 5-2: Wind Speed distribution in a height of 65 m (Rayleigh) at the chosen sites .....................................................................................................................................5-3 Figure 5-3: Capacity Factor at site „Sam Son“ (poor wind)...............................................5-5 Figure 5-4: Capacity Factor at the site “Tuy Phong” (fair wind) .......................................5-5 Figure 5-5: Capacity Factor at the Site “Phouc Minh” (good wind) ..................................5-5 Figure 5-6: Height dependence of capacity factor Vestas V52 ..........................................5-6 Figure 5-7: Averaged investment costs wind turbine .........................................................5-7 Figure 5-8: Relation hub height to investment cost ............................................................5-8 Figure 5-9: Costs of incidentals as a percentage of wind turbine costs. ...........................5-11 Figure 5-10: Cumulative Frequency distribution of sample wind turbines LEC over all sites ......................................................................................................................5-16 Figure 5-11: Potential new capacity in dependence of tariff-level ...................................5-17 Figure 5-12: Potential new capacity in dependence of tariff-level ...................................5-18 Figure 5-13: Sensitivity analysis of selective aspects.......................................................5-19 Figure 10-1: Proposed structure of the REDO in Vietnam...............................................10-9 Figure 10-2: Cash flow between key parties ..................................................................10-12 Figure 10-3: Key parties involved and their role in the support mechanism..................10-13 Figure 11-1: Development of total annual remuneration of wind power according the feed-in regulation. ......................................................................................11-1 Figure 11-2: Composition of cost coverage of total remuneration. Here we compare against the Avoided Cost Tariff, the value of Certified Emission Reductions and external benefits. Resulting additional costs are given in red with the values on the top of the bars giving the exact value of the additional costs for each year. ................................................................................................................11-2 Figure 11-3: Composition of cost coverage of total remuneration. Here we compare against the Avoided Marginal Costs (brown bars), the value of Certified Emission Reductions (light blue bars) and external benefits (green bars). Resulting additional costs are given in red with the values on the top of the bars giving the exact value of the additional costs for each year. ............................................11-3 Figure 12-1: Development of surcharges on power consumptions due to additional costs from wind power remuneration. .............................................................12-4 Figure 12-2: Comparison of individual submission of projects under CDM (left) vs. submission as a Program of Activity (right). ............................................................12-13

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1. International Regulatory Mechanism Renewable Energy is an indispensable part of a sustainable energy system. The government of Vietnam acknowledges deployment of renewable energy as a “goal of national interest” (Decree on encouraging and supporting renewable development). It is therefore that the government of Viet Nam follows the example of many other countries in promoting renewable energy deployment. Albeit market forces should be given a central role [Ver09], it is still necessary to implement public policies to foster renewable energy deployment, as technologies are often still not fully competitive with conventional energy carriers under present framework conditions. Consider-ing the large investment needed to establish renewable energy in the energy sector, it will be crucial to make RE power plants a capital magnet [Lan03]. Moreover, long-term stability of support mechanisms and of revenue streams generated is needed to attract investment in generation plants and manufacturing facilities. At the same time, stability allows to reduce the cost of capital since investors will appreciate the investment security. In most countries deployment of renewable energy is promoted by one main support instrument supplemented by a series of other support means. There is a long and ongoing discussion, both on the theoretical level as well as in practical terms, on which main support instruments are the best suited for promoting power generation from renewable energies. This section will present the most common support instruments, point out their differences and compare their advantages and disadvantages. Further, international examples on actual support schemes are given and findings are transferred to the Vietnamese situation. We distinguish thereby between quantity-based (Quota Obligations and Tendering Schemes) and price-based mechanisms (Feed-In Tariffs). Even though the focus is on the promotion of wind power, we cover also other technologies since the support instruments are usually not exclusively targeted on wind power.

1.1 Price-based mechanisms

Figure 1-1 illustrates the working principle of a price-based instrument. The state acknowledges the importance of RE proliferation by setting a fixed price pRE. Any RES-E generated will be bought by the obligated entity at this price. The price of electricity is being fixed independent from the quantity and electricity suppliers solely act as quantity adjusters. Any technical progress or economies of scale will not lead to a lower price, but to more generation (due to lowering of the supply curve). Generators will be able to commission plants using RE technologies until their marginal costs equal the tariff level. “The price of RES-E generation is fixed and the quantity is flexible”

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Figure 1-1: Price-based instrument

1.1.1 Feed In Tariff

Feed-In Tariffs (FIT) are considered to be the most efficient price-based instrument for supporting RES-E deployment. FITs generally consist of three essential building blocks: (1) obligation to connect, (2) obligation to purchase and (3) obligation to pay a certain price for RES-E. They provide the highest security and long-term planning reliability to investors. There-fore capital costs are a lot lower in countries using Feed-In Tariffs compared with countries relying on other main support instruments [Rag05]. A Feed-In Tariff (also referred to as Fixed Price- or Minimum Price Stan-dard) requires grid operators to buy electricity produced from renewable energy sources (at a fixed price). Feed-In Tariffs are generally designed together with a purchase obligation. The system leads to a regulated Power Purchase Agreement (PPA) for RES-E. A core element of a Feed-In Tariff is, that the price is fixed and the amount of generation is adapted [Lan03]. An individual generator will produce electricity until its marginal costs equal the regulated price. Feed-In Tariffs can be designed as a fixed remu-neration or as a surplus onto the market price of electricity (Premium FIT). Currently FITs are used in 20 of the 27 EU member states as central support instrument. Tariff setting There are two main ways of setting the overall return that RE developers receive through FIT policies. The first is to base the FIT payments on the levelised electricity generation costs of renewable power plants; the second is to base the FIT payments on the value of that generation to the utility and/or society (avoided costs). In the first approach, the payment level is based on the levelised cost of RE generation, plus a prescribed return. The advantage of this approach is that the FIT payments can be specifically designed to ensure that project investors obtain a reasonable rate of return, while creating conditions more conducive to market growth.

Generation Q

Price/costs Supply curve S

Demand DPRE

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The second method of setting FIT payments is by estimating the value of the renewable energy. This value can be defined in a number of ways, either according to the utilities’ avoided costs, or by attempting to internalize the external costs of conventional generation. This can be considered the “value-based” approach, which contrasts with the first, “RE project cost-based” approach. Value-based FIT payments require quantification of these numerous benefits (either to the utility, society, and/or the environment) to establish the total compensation, potentially leading to a high degree of administrative complexity. The challenge is that value-based approaches may not match the actual RE generation costs, and may provide insufficient payments to stimulate rapid market growth. Alternatively, they may provide payments that are higher than generation costs, leading to cost-inefficiency and windfall profits among investors. Stepped tariff designs The basic (flat) tariff FIT can be amended with several complementary elements. One is a stepped tariff design, aiming to decrease windfall profits. The actual level of remuneration that a plant receives depends on its capac-ity, location and wind resource and is regulated by the law. In order to avoid windfall profits of particular plants in case of a flat tariff design the tariff should be designed stepped on (at least one) of the following factors.

(1) Site quality The generation costs of wind power plants strongly depend on the resulting full-load hours for a particular plant/site combination. Figure 1-2 shows the generation costs in dependence of full-load hours for a reference plant. If a flat tariff design (same per kWh remuneration for all load factors) is used a generator will receive the same per kWh remuneration in case of 2000 (see Figure 1-2, case a) and 3000 (see Figure 1-2, case b) full-load hours, but have a higher profit in case b. With this tariff design it is likely that only the best sites will be exploited. The higher profits will lead (due to the system of burden-sharing) to higher costs for the electricity consumers.

Figure 1-2: Flat tariff design [Kle08]

a b

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Applying a load factor dependent per kWh remuneration shall lead to a more equal distribution of generator profit. Figure 1-3 shows the generation costs and the annual support as a function of full load hours (The actual example is the Netherland’s support tariff model). The stepped tariff design leads to a homogenous generator profit that is nearly the same over all load factors. As a result of the stepped tariff design, electricity costs will decrease for customers.

Figure 1-3: Site quality dependent stepped tariff design [Kle08]

(2) Plant size

Common RES-E technologies have different per kWh electricity generation costs depending on the plant size. Economies of scale lead to a significant cost reduction in case of large plants. To encourage investors building also small-/medium scale plants and to avoid over subsidizing of large installa-tions a capacity stepped tariff design can be used. Almost all European with a FIT legislation use different levels of remuneration depending on the RES-E plant size.

Figure 1-4: Capacity dependent stepped tariff design [Kle08] Figure 1-4 shows the Luxembourg example of a capacity dependent stepped tariff. Plants between 1 and 500kW receive fix remuneration, plants’

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remuneration from 501kW upwards is calculated with by a (exponential) formula specified in the law.

(3) Renewable Energy Electricity generation costs vary considerably according to the RE source used for production. Each RES technology has a different level of maturity and thus must be remunerated on an appropriate tariff level (E.g. that large hydro power does not receive the same specific remuneration as distributed PV).

Advantages Disadvantages • Diversity of electricity genera-

tion costs is taken into account • Over-compensation of certain

plants is avoided • Hence, burden for consumers is

decreased => cost-efficiency

• Administrational complexity • Less transparent

Table 1-1: Advantages and Disadvantaged of a Stepped FIT FIT Design Guidelines When designing a Feed-In Tariff, policy makers should keep to the follow-ing guidelines, as a Feed-In Tariff is a very sensitive instrument and lacks from interaction with the free market.

(1) Ensure that the Tariff is set sufficiently high (calculation of the tariff level can be based on the marginal costs of electricity pro-duction or on avoided external costs)

(2) It is very important to foresee to install a degressive element for

new installations in order to force technological learning

(3) FITs have to be revised regularly and checked if the tariff is still on an appropriate level (Power plant prices or prices of certain re-sources may undergo unexpected changes)

(4) Include stepped design in order to prevent generators making un-

necessarily high profits from certain plants

1.1.2 Premium tariff design

Unlike the Fixed Feed-In Tariff design, premium regulations do not provide RES-E generators an overall guaranteed remuneration, but a fix Premium that is paid on top of the market price of electricity. The development of the market price has an influence on the overall remuneration level. Hence, the Premium Tariff represents a modification of the fixed tariff. The Premium

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FIT is not as competition-oriented as a tendering mechanism, but allows for RES technologies just about to turn profitable a good option to benefit from the market. Currently, most of the European countries with Feed-In Tariffs chose the fixed tariff model. Premium tariffs are only applied in Spain, the Czech Republic, Slovenia, the Netherlands and Denmark (only for onshore wind).

Advantages Disadvantages • Higher compatibility with a

liberalized electricity market • Match between supply and

demand may be alleviated

• Causes higher costs for consum-ers due to higher risks

• Less investment security

Table 1-2: Advantages and Disadvantages of Premium FIT

1.1.3 Example: Spain

Spain has installed a combination of a fixed- and premium FIT as a very successful support scheme enabled by Royal Decree 436/2004. The system consists of the implementation of a regime by which each kWh produced with renewable energies is paid to the producer at a special price, higher than the market one. The actual fixed remuneration is calculated as a percentage of the yearly average electricity tariff (methodology of calcula-tion: Royal Decree 1432/2002). The producer can choose between a fixed price and a “premium” added to the price negotiated in the electricity market. The choice is valid for one year; after that the producer can decide to maintain the system or change to the alternative [Rag05]. The number of plant operators choosing the Premium option constantly rose, because the combination of a relatively high Premium and a high market price led to higher producer profits compared with the fixed tariff design. In 2004 only 5% of the electricity from renewable sources was offered on the market, by 2006 already 93% of the plant operators decided to market their electricity using the Premium FIT. The premiums and the fixed tariff rates are set by the Government on an annual basis (this is a difference to the German system, in which the tariff is set fix for 20 years [Rag05]). Notwithstanding the rather short period of fixed support, the overall duration of support (with annually volatile tariffs) is about the technical lifetime of the plant. Spain’s FIT features technology specific support and a plant capacity dependent stepping. The Spanish system of tariff degression is not based on the prediction of future technological learning and resulting fixed annual digression rates. Degression rates (or more generally: any adjustment of the tariff, increase or decrease) are set on an annual basis, thus allowing quickly reaction to any unforeseen changes in the energy sector. In Spain any tariff re-adjustment is applied to new installations as well as to existing ones. The Spanish system does not allow any limiting of producer profit at extraordinary good sites. It does not feature a stepped tariff design based on site quality.

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The Spanish support scheme has triggered considerable capacity additions in plants producing electricity from renewable sources. In 2008 Spain has installed 1,609 MW of wind power, the total installed generating capacity now totals to almost 17 GW, making Spain the second largest producer of wind power in Europe [EWE08]. The factor of domestic production in wind power projects is high and wind turbine manufacturing companies with remarkable world market shares (third highest capacity installed) have emerged (Gamesa, Ecotecnia). Its shortcomings are seen in the lack of tariff stepping, no extra support for newest technologies and that ex post tariff adjustments are applied to new as well as existing plants; this in theory decreases long-term security.

1.1.4 Example: China

China just recently (July 2009) has installed a new regulatory framework which promotes a Feed-In Tariff as main support instrument for onshore wind power generation. Other technologies are fostered on a quasi case-by-case basis. The country targets to increase the share of electricity from renewable energy to 15 % by 2020 according to the “National Renewable Energy Development and Utilization Plan” issued in September 2007. China’s first Renewable Energies Law was implemented in 2005, encourag-ing the development of all forms of grid-connected electricity generation from RES (applicable to hydro-power with size restrictions only) in order to meet the requirements set out in the national plan. The Chinese RE Law outlines two pricing options for electricity produced from renewable energy sources: • Guided pricing through a tendering process • Government fixed pricing

Guided pricing through tendering was applied to (onshore) wind power until the installation of the Feed-In Tariff and was abolished due to unrealistic low bids submitted by project developers; fixed pricing still applies to biomass power for example. The latest change in legislation has removed the tendering system (guided pricing) for wind power plants and imple-mented a fixed Feed-In Tariff instead. According to a pricing guideline elaborated by the National Development and Reform Committee of China the country’s onshore wind resources are classified into four categories. The classification is conducted in a simplified way, treating regions as areas with uniform wind properties. Hence only a site’s location in a certain region is relevant for the height of the tariff, not the actual wind conditions on site. The tariff varies between 0.51 and 0.61 RMB (7.5 to 8.9 US-cents) per kilowatt-hour [NDRC09]. The additional costs (compared with electricity generation mainly from coal) arising through a higher share of renewable energy in the national energy mix are finally shared among electricity customers in the way of higher prices per kilowatt-hour (renewable surcharge). The provincial grid-

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operator is the responsible entity to organize this sharing [NDRC09]. The State Council’s Pricing Department is responsible for the setting of the surcharge. The surcharge is imposed on electricity consumers on a con-sumption dependent basis. The costs due to grid connection and potential reinforcement are borne by the grid operators and may be passed on to electric utilities. The renewable energy surcharge is partly used to finance the additional costs of a higher share of electricity produced from renewable sources and to finance the “Renewable Energy Development Fund” [WWI06]. In 2006 the surcharge was set at 0.32 US-cents per kilowatt-hour, but the renewable energy surcharge will be reviewed annually by the pricing department in order to react to the actual situation of renewable energy development [Mar09]. Agricultural electricity users and end-users in Tibet are exempt from this RE surcharge. Beyond, the government offers preferential loans for developers of RES-E projects and grants tax benefits to projects listed in the “Renewable Energy Industrial Development Guidance Catalogue”. The “Renewable Energy Development Fund” will inter alia support R&D in the renewables sector, stimulate economic growth in rural areas and help grid companies with subsidies where additional costs are not recoverable via the standard tariff. Management of the fund will be worked out by finance, energy and pricing sectors of the State Council. The fund’s income resulting from the renew-able energy surcharge is estimated to be 689 million USD in 2009 [Win09 2]. China has been showing a literal boom of renewable energy in the last years. Wind power has been the fastest growing technology with its total capacity doubling the fourth year in a row in 2008 (approximately 12GW have been added in 2008 [EWE09]). In addition to the remarkable capacity additions, a vital domestic production industry above all in the field of wind and PV power has emerged. China currently has four major manufacturers produc-ing competitive self-developed wind turbines in the relevant capacity range between 600 and 1500kW, inter alia Goldwind, China’s largest producer. Many more manufacturers offer small wind turbines (below 200kW) or turbines manufactured under license from European companies [Eco09]. These achievements are only partly triggered by the support scheme, although it shows some good approaches. The high capacity additions are triggered mainly by the ambitious government plan (that literally obliges utilities to install RES-E generation capacity. Among others the change of legislation from tendering scheme to FIT has improved China’s position as investment country. Investors now have a lot more long-term security because the assigned plant operators are given a binding purchase guarantee for all the electricity produced (Renewable Energies Law, Article 14). Furthermore the installed FIT makes the support of electricity generation from renewable sources more cost-effective by stepping the tariff level dependent on site-quality (onshore wind) and installing a system of burden-sharing (Renewable Energies Law, Article 20). It also aims to limit the negative impact on the people’s welfare by exempting agricultural busi-nesses from the renewable surcharge. By mandatorily using a significant

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share of the income from the renewable surcharge for R&D activities in the renewables sector (Renewable Energies Law, Article 24) Chinese policy makers have made a foresighted decision, enabling more growth in the domestic production industry and finally making China more and more competitive with European manufacturers of RE technology. However the support system does have some weaknesses: Many of the statements in the law are formulated too general in order to be practical and the tariff does not include degression (which could foster more technologi-cal learning). Due to the lack of security about the height of remuneration for electricity produced from certain RE technologies, international inves-tors are hesitant to invest in renewable power plants. However, the domestic production industry for renewable equipment show good prospects in the view of international investors. The Feed-In Tariff for wind now has the potential to trigger real sustainable growth in the generation sector. Due to the good national and international feedback the Chinese government recently has announced to install a similar FIT applicable for PV generation projects [Ren09-2].

1.1.5 Example: India

India has announced the installation of a FIT in the second half of 2009. This Feed-In Tariff proposal foresees that it should foster all forms of electricity generation from renewable sources technology. Like China, India has a rather ambitious renewable energy action plan, the so called “National Action Plan on Climate Change”. It constitutes that the share of electricity generated from renewable sources in the country’s total annual electricity consumption should equal 5% in 2010 and from then on rise by 1 percent-age point per year for the next ten years [Gip09]. Today only three percent of the electricity of the nation’s power mix comes from renewable sources [Wor09]. The tariff level is technology specific as determined by the Central Electric-ity Regulatory Commission (CERC) on basis of the actual generation costs of each technology plus adequate producer profit (19% ROE before tax) [Ren09-1]. It is still unclear in this stage of tariff-design whether the CERC is going to set the tariff on a case-by-case basis or general rules are going to be applied. In the case of wind power it is foreseen that the tariff level is stepped on a site-quality basis. The wind resources are classified into four categories (bands) representing the installation’s capacity factor. Band 1 is wind-class 2, band 2 is between wind-class 2 and 3, band 3 equals wind-class 3 and band 4 applies for sites with a potential greater than wind-class 3 [Gip09]. This results in tariff levels between 7.8 and 11.7 US-cents per kWh. The second RE technology as FIT has been announced for is solar PV. The tariff level for PV ranges between 28 and 39 US-cents per kWh. CERC’S tariff proposal includes the possibility to re-adjust the tariff level annually [CER09]. It has not yet been stated in the Indian FIT proposal how additional costs (grid-connection/enforcement and higher generation costs) will be distrib-

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uted. In principle there are two options: burden-sharing among (all or a selected group of) electricity users or financing through an auxiliary fund. No responsible entity has been defined yet to organize the financing. The Indian FIT proposal offers tariff payment for a sufficient time period. Technologies with a modest investment (e.g. Wind) will receive the fixed tariff for 13 years, technologies demanding a higher investment (PV and CSP) will have a guaranteed payment period of 25 years and small hydro plants (less than 3MW) are qualified for receiving the tariff for 35 years [Gip09]. The Indian system contains design-elements that are crucial for a viable Feed-In Tariff. The most important issue, long-term security for investors, is confirmed by sufficiently long payment periods. Together with a tariff level set sufficiently high and enabling high producer profit, this reliable political framework will help decrease capital costs for investments for RES-E plants in the long-term. Indian government estimates that until 2012 investments worth 21 billion USD will be made in the renewables sector. The system allows – via tariff stepping on site quality – to limit excessive profits for producers. Together with a tariff level adapted to the specifics of different technologies this provides an overall good cost-efficiency and limits the impacts on financially-weak electricity users and caps the negative implica-tions on economical growth. The option that allows CERC to review the tariff level annually enables the tariff regulator to react on any severe change in RE technology, e.g. a technological breakthrough in PV.

1.2 Quantity-based mechanisms

Figure 1-5 illustrates the working principle of quantity-based mechanisms (Quota Obligations, Tendering Schemes). The target (quota) is usually set in form of a mandatory percentage of the annual electricity generation, but it is also feasible to design the quota as a compulsory generation capacity target. The problem with capacity based quotas is the limited comparability between RES-E plants and conventional plants (load factor, mostly non-deterministic generation). The state promotes RE deployment by setting the demand (D) fixed at QRE. The demand is not to be seen as a real demand for RES-E, but as a demand for certificates (see example from the UK, 1.2.2). As a result the “artificial” demand (quota) will be met by producing RES-E in order of its generation costs. The higher the quota is set, the more cost-intensive RE sources can be exploited. Due to potential penalties for lack of fulfillment, the set quota shall be exactly met in theory. “The quantity of RES-E generation is fixed and the price is flexible”

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Figure 1-5: Capacity-based mechanism

1.2.1 Quota Model

A Quota Model (also referred to as Renewable Set-aside or Renewable Portfolio Standard) obliges a certain stakeholder in the supply-chain to provide a specified minimum share of total electricity usage from renewable energy sources. The quota (minimum share of RES-E generation) is usually set as a long-term target (e.g. until 2027 in the UK [Hel06]). The obligated parties comply with the obligation by presenting Tradable Green Certifi-cates certifying the generation of a certain amount of electricity (but a quota model does not have to include TGC in any case!). The certificates are issued for each kWh of RES-E produced or can be purchased from other entities having fulfilled the obligation. Hence these (tradable) certificates have an economic value generating an extra income to RE electricity producers: They market the electricity produced on the free market as well as the certificates. With a Quota Model a second market for certificates will emerge. Interna-tional trade with certificates is practically not feasible, as Quota models differ considerably from country to country. A viable TGC-market is a crucial pre-condition for an efficient implementation. That kind of market can only develop within a deregulated electricity market with a minimum number of market participants. In a situation with monopolists or quasi-monopolists the system will work only inefficiently. In order of their generation costs RES-E will be produced until the targeted amount is reached. The least expensive renewable energy will be imple-mented first. Quota Model Design Guidelines

(1) Quotas should be set as long-term targets in order to guarantee a long-term perspective to investors/stakeholders

Generation Q

Price/costs Supply curve S Demand D

QRE

4890S11/FICHT-5530494-v2 1-12

(2) Guaranteed minimum tariff should be implemented in immature

markets

(3) Additional support besides the quota must be foreseen to foster less mature technologies

(4) Sufficient liquidity and competition must be guaranteed in order

to establish a viable TGC market

(5) Penalties should be imposed on parties not fulfilling the quota ob-ligation

(6) The penalty must be set higher than the marginal costs of produc-

tion

1.2.2 Example: United Kingdom

The United Kingdom has until recently failed to implement a viable policy instrument to foster RES-E sufficiently. Consequently the UK government swapped its main support scheme in 2002 from a tendering scheme (the Non-Fossil Fuel Obligation, NFFO) to a quota obligation [EuC09], the so called “UK Renewable Obligation” (RO). The main support instrument is supplemented with features providing technology specific support, tax exemptions and investment grants. The RO is the UK’s main support scheme for RES-E and coupled with a TGC system, named “renewable obligation certificate” (ROC). A ROC is a green certificate issued to an accredited generator for eligible renewable electricity generated within the United Kingdom and supplied to customers within the United Kingdom by a licensed electricity supplier. Generally one ROC is issued for each megawatt hour (MWh) of eligible renewable output generated. The official price per ROC will (just like the quota) increase gradually over time. The price of the ROC (£/MWh) depends on the energy source used for RES-E generation. The RO places an obligation on suppliers to produce an increasing share of their electricity sales from renewable sources. In 2006/2007 the obligation was 6.7 % and will increase to 15.4 % in 2015/2016 [Win09-1]. Suppliers comply with the obligation by presenting a sufficient amount of ROCs to the “Office of Gas and Electricity Markets” (OFGEM). If suppliers cannot present a sufficient amount of certificates, they have to pay a “penalty” into a fund. The fund’s revenues are then redistributed among the suppliers that have presented certificates [Ofg09]. The UK government implemented some major changes to the RO system in early 2009. These changes now enable supporting different technologies on appropriate levels. The revised system foresees that ROCs are provided to generators dependent on the energy source (so called “banding” of tech-nologies). For example one megawatt hour produced from landfill gas will

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entitle to receive 0.25 ROCs, whereas one megawatt hour from offshore wind will get 2 ROCs1. In the new system suppliers will not any longer have to fulfill the quota regarding a certain amount of electricity produced, but they will be obliged to present a certain amount of certificates. This regula-tion aims at fostering the implementation of new technologies and takes into account the higher investment/higher electricity generation costs. It is estimated that the new support framework will increase the RES-E deploy-ment by over 40% compared to the actual RO. The UK’s wind resources are the largest in Europe, but the country has not seen yet no growth of wind power accordingly. In the entire UK only 3,200MW has been installed by 2008 [EWE08]. After the swap an increase in capacity addition was noticeable. The system’s shortcomings are seen in the high emphasis on the deployment of the cheapest technology rather than developing innovative technologies (which are in fact not close to the market) and a relative costly participation in the ROC system, virtually excluding new market entrants virtually from compe-tition; this issue has been reduced with the 2009 changes. Beyond, investors are left in a situation of uncertainty as usually only limited short-term contracts are offered to the generators of “green” electricity [Lem09]. Also the system investment grants are distributed is not very transparent and reliable.

1.3 Tendering Scheme

Tendering schemes belong to the quantity-based instruments and are a “special form” of a quota obligation. Producers of electricity from renew-able sources compete in individual call for tenders against the backing of a previously set amount-allocation. The winners of the bidding procedures receive a unilateral power purchase agreement (PPA) for the electricity they produce. Depending on the exact design, there are sometimes separate tenders for different RE technologies (e.g. so that solar PV does not have to compete with large hydro). Generally, proposals (bids) from potential developers are accepted starting with the lowest bid and working upwards, until the level of capacity or generation required (in the quota) is achieved. The winner of each bidding round usually will be the one using the technol-ogy with the lowest costs. The tendering is repeated periodically. Today only France applies tendering for large projects over 12 MW capacity, Ireland swapped to FIT and the UK to a Quota System. The system features a strong competitive element but implies the danger that bids are too low and do not even cover the generation costs. In the past several successful bids from Tendering rounds were not commissioned or only commissioned on a low quality-level. A penalty for these “non-performance” bids is inevitable. A Tendering Scheme only provides suffi-cient support for large projects (which usually have the lowest specific

1 http://www.enviros.com/PDF/BN020RenewablesObligation.pdf

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costs), the development of small-/medium scale projects is usually not fostered by this support instrument.

1.3.1 Example: Portugal

Portugal promotes Renewable Energy primarily through a fixed Feed-In Tariff and Tax incentives. Complementary to the installed Feed-In Tariff the state issued a call for tender for large amounts of wind power in 2005. In addition to Portugal’s environmental targets (following EU directive 2001/77/EC the countries target is to cover 39% of its electricity consump-tion with RE) the tender aims on establishing a viable renewable industry. In the long-term this ought to lead to a higher share of domestic production in renewable energy projects and thus reduce commissioning costs. Beyond, a strong domestic renewable industry leads to new export possibilities and creates jobs. Tendering Scheme The (international) tender is set at 1500 MW and split into two phases: In Phase A 800MW and in Phase B 400 MW of generation capacity are tendered. Each bid has to cover the entire capacity tendered out. In case the capacity requirements (and the project characteristics shown below) are met in an extraordinarily way by certain bidders, the tender-jury may assign extra capacity to those bidders. The winner of Phase A is automatically excluded from Phase B. The whole capacity tendered in both Phases ought to be commissioned until 2013. The incoming bids are assessed by a tender-jury on basis of a priori elabo-rated assessment and weighting scheme. The project proposals should at least show the following characteristics (listed in order of their importance):

(1) Increase economic efficiency of RES-E proliferation (2) Boost domestic production of the renewable energy industry

(3) Bring economical development to less developed regions

(4) The bidding party should be able to technically develop the pro-

ject

(5) The bidder should put commitment into the further development of wind power (e.g. R&D)

By only tendering a limited amount of generation capacity each time, the Portuguese approach follows restrictions resulting from insufficient grid development. Hence the risk of grid bottlenecks is reduced. As soon as the grid system has been reinforced, another tendering round may be issued. The assessment criteria focus on “soft-factors”, not primarily on cost-efficiency. This approach makes it for improbably low bids unlikely to be

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selected and is targeted on the long-term sustainable development of renewable energy in the country.

1.4 Conclusion

All three types of main support instruments investigated here have advan-tages and disadvantages (see Table 1-3). Notwithstanding it is not only the choice of a support scheme that makes it efficient, but the right design. Furthermore it is possible to combine the advantageous properties of different schemes. For example there are Feed-In Tariffs which are amended with design features of a quota obligation or with investment grants, see international examples. There is some understanding that the choice of instrument depends also on the maturity of the technology to be promoted. The more mature a technol-ogy is the more should the support rely on market forces and the lesser should be the direct intervention of the state (see Figure 1-6). For example Investment- or Tax Incentives are well suited well for technologies in early development stages with costs much above conventional energy technolo-gies. Feed-In Tariffs are a good option for RE technologies in the interim stage of development (e.g. offshore wind, small onshore wind, medium hydro), whereas well-developed mature technologies (e.g. large hydro, onshore wind, geothermal) are preferably supported by a Quota System based on TGC or a Premium Feed-In Tariff. However, this assessment emanates from well functioning markets with a large number of competi-tors. In practice, power markets features often only a limited number of incumbent utilities so that competition is very restricted and the typical benefits of governance by markets do not occur. Under such circumstances, quota systems quite likely fail to deliver the targeted amount of renewable power. Then, feed-in tariffs are still the instrument of choice even for mature technologies like wind power. In this regard, the choice of instru-ment rather reflects the state of deregulation rather than the state of technol-ogy. Figure 1-6: Applicable Support Instruments

Immature Interim MatureInvestment grants /

Tax subsidies Fixed Feed-In Tariff Quota System on

TGC or Premium FIT

Tendering Scheme

RE technology advance

Level of market orientation

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Advantages Disadvantages Fe

ed-I

n T

ariff

• Long-term security for investors • Transparency • Proven to be very effective • Great flexibility: Can be designed in the scheme to

account for changes in technology and the market • Encourages steady growth of small- and medium scale

producers • Low transaction costs, low costs for society • Good technological differentiation • Low capital costs due to “low” risk

• Far away from the “real market” • If tariffs are not adjusted over time (degression), con-

sumers will have to pay unnecessarily high prices • Can involve restraints on renewable energy trade due to

domestic production requirements • Needs to be amended with elements from other instru-

ments in order to support “new” RE technology • Nations RES-E goals might not be reached fully as a

(fixed) FIT creates a market independent from the “real” market

Quo

ta M

odel

• Competition between technologies • Cost-efficient when implementing large amounts of

RES-E generation • Support of mature RES technologies • Competition among investors • Set quota (government RE proliferation goal) will be

exactly reached

• Complexity of the system • Risk of supporting only the least cost technology • Uncertainty among investors • No reduction of generator profits feasible • Complicated implementation of technology specific

support • High transaction costs

Ten

deri

ng

Sche

me

• Competitive element • Put large public attention to RES-E • Good for supporting mature RES technologies and

large projects • Competition among investors

• Does not foster a variety of technologies, only the most cost-effective

• No remarkable success (as the last European country Ireland switched from tendering to FIT in 2005)

• Danger of “stop and go” support • Competition may drive costs too low • Does only support large projects

Table 1-3: Advantages and disadvantages of particular support instruments

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Not regarding the actual support scheme there are some minimum standards instruments should feature. Minimum criteria:

(1) Support should cover a sufficient timeframe (compare with tech-nical lifetime of plants)

(2) Level of support should allow coverage of extra costs arising

through RE usage

(3) Instrument should acknowledge specifics of technologies

(4) No unlimited support in order to force maturity

(5) A sustainable energy policy should not rely on a single technol-ogy, but a technology portfolio to reduce risks

(6) Any ex post adjustment of the support instrument should only

cover new installations

(7) Instrument should inhibit excess profits Market participants from all EU member states acknowledge that the most important criterion of RE support is - whatever support instrument is chosen - the stability of the instrument and a sufficient period of support. This attracts capital and reduces risks as well as financing-costs. Not the profits of single generators make a support scheme efficient, but a low risk level for potential investors. The issue of ultimate cost-efficiency for consumers is not considered to be of the same concern as “soft-factors2” enabling a long term and sustainable development of a country’s the energy sector.

1.5 The Choice of Main Instrument considering the Vietnamese Framework Conditions

Aside from hydro power, the current usage of renewable energy for electric-ity generation is concentrated in small off-grid systems. For achieving the goal of promoting RES-E also in the grid-connected sector an incentive-system is indispensable. Very low (regulated) electricity prices and fuel subsidies for the monopolist EVN contribute to the necessity of such a support scheme. Beyond, mentionable expansion of grid-connected RE electricity generation will qualify to deal carbon certificates on the interna-tional market and therefore create an extra income, at the same time improv-ing the country’s currency account balance. A reliable planning framework for RE projects (grid-connected) will also attract more (international) investors.

2 E.g. R&D in innovative technologies, encouraging domestic production and developing yet undeveloped regions.

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In order to decide about the suitable support scheme for Vietnam it is necessary to review the structure of the energy sector and know about the Government’s long term targets according RES-E deployment. Especially information about the level of deregulation, market participants and poten-tial (quasi-) monopolists, the level of grid development and anticipated demand forecasts is crucially needed. National RE goals According “Electricity Plan VI” Vietnam has the objective to have a share of 5% of its grid-connected electricity generation by 2020. This goal is ambitious, particular considering the fast increasing electricity demand. In the near future it has set a modest goal of adding 100-200MW of renewable electricity generation capacity by 2010. The Vietnamese policy makers give the highest priority in RES-E deployment to the cheapest RE source (bio-mass) and mainly focus on the proliferation of off-grid systems. Off-grid systems are believed to be the most cost-efficient and only way of electrify-ing very remote areas with no access to the national transmission grid system, even in the future. Up to 2015, 1,533 MW of grid-connected (small) hydro and biomass generation capacity ought to be installed. In the period 2016-2025 another 1,030MW generation capacity including (small) hydro-, geothermal- and wind resources has to be commissioned according to the national “Masterplan for Renewable Energy”. Deregulation of electricity market

The electricity market in Vietnam is in the process of deregulation. The 2004 released Vietnam Electricity law forms the foundation for a transfor-mation of the regulated electricity sector into a competitive electricity market. This deregulation will happen in stages: Phase 1 (2005-2014) foresees competitive generation with an increasing share of IPPs and a single buyer (EVN), Phase 2 (2015-2022) enables IPPs to also sell their (wholesale-) electricity directly to major end users. After 2022 the electric-ity sector will be opened fully also to retail- / household sales. The Govern-ment still interferes with the market by limiting the electricity price at rather low 0.05US$/kWh. Beyond, EVN is subsidized by regulated fuel-costs lower than the market price.

The state strongly interferes with the market Market participants and –power

By now almost the entire electricity sector is run by a quasi-monopolist, the Electricity of Vietnam (EVN). The EVN is a state-owned utility established in 1995. It is engaged in generation, transmission and distribution of elec-tricity in the whole country. Its market shares are 100% in the transmission-, 95% in the distribution- and 78% in the generation sector. Only the genera-tion sector has been opened to private market participants yet. Since 2001 IPPs have the possibility to make a PPA with EVN and feed electricity into EVN’s grid. EVN will focus on plants with more than 100MW capacity in the future and therefore give smaller generation facilities into private hands.

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The state will maintain its monopoly over electricity transmission, regula-tion of the national electricity system, and the construction and operation of large power plants considered significant for socioeconomic or national defence and security reasons [Fre05]. The quasi-monopoly of EVN makes it hard for IPPs newly entering the market

No relevant IPPs, one quasi monopolist

Possibility to make an PPA is already foreseen in legislation

State will remain responsible for the transmission grid and the regulation in future

Demand forecast The Vietnamese economy has grown fast over the recent years. In this timeframe the electricity demand has even risen faster. Notwithstanding the large increases the actual per capita energy consumption in Vietnam is still modest. Hence even an accelerated growth of demand is forecasted. In 2015 the energy demand will be on 2.5 times the 2006 level and in 2025 5 times. Therefore after 2015 crucial changes will have to be made to the Vietnam-ese supply infrastructure.

Very fast growing electricity demand Grid development The Vietnamese grid system is well-developed and relies on a 500kV backbone. The only TSO (EVN) states that the grid will be able of any capacity addition of renewable generation without needing reinforcement. At least the modest targets set in the “Masterplan” will be able to connect.

No grid-bottlenecks expected

Import dependence Vietnam has rich energy resources in coal, oil, natural gas and renewable energies. Due to the rising electricity demand Vietnam is likely to become a net-importer of coal and (crude-) oil by 2015. Implementing a noticeable amount of RES-E would limit the future import dependency as well as help improving Vietnams current currency account balance. Conclusion A Feed-In Tariff is recommended as the most suitable central support instrument for Vietnam. It is internationally proven and fits best to the boundary conditions in Vietnam.

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(1) As pointed out above, the highest priority when designing a sup-port scheme for RES-E is to guarantee a reliable level of support over a sufficient period of time. A Feed-In Tariff is usually de-signed for timeframes comparable to the technical lifetimes of plants. This will in Vietnam increase for investors’ security and also attract international investors. As risks related to RES-E pro-jects will decrease, capital costs (which are on a very high level currently) will go down, thus encouraging even more investment.

A Tendering Scheme does not give any long term planning secu-

rity (is known for stop-and-go support) and is therefore assessed inferior to the Feed-In Tariff in this aspect.

(2) A Feed-In Tariff has to feature two main building blocks related

to the grid operator: Connection- and Purchase Obligation. The Vietnamese electricity market is still heavily regulated and does only have few market participants. In the transmission system sector there is no competition at all. The state will maintain its “supervising” role over the transmission grid system still in the future. This makes it easy to oblige the (quasi-) monopolist EVN to connect RES-E plants to its grid and to purchase the electricity produced by them. Hence there is going to be no dispute over who is responsible to fulfill these obligations. A single transmis-sion grid operator makes it also easier to install a system of cost distribution arising through the purchase obligation.

On the contrary a Quota System requires an already strongly

competitive and deregulated market. A single monopolist will not fulfill the quota and prefer paying any potential penalties. Another prerequisite for a Quota system is that a market for green certifi-cates can emerges; with no mentionable IPPs this is not possible.

(3) The actual (quasi) monolist generator EVN stated to focus on

generation with more than 100MW capacity in the future. Typical power plants using RES usually have a capacity of approximately 30MW. This capacity category is going to be implemented pref-erentially and could give new IPPs to enter the market. Many small- and medium scale projects have a much lower risk than implementing a few large projects. A Feed-In Tariff offers – as it can be designed capacity stepped – good remuneration prospects to also small- and medium scale projects.

Whereas Tendering Scheme and Quota obligation have proven to be only successful in the deployment of large amounts of RE gen-eration capacity with mature technologies.

(4) The European countries using a Feed-In Tariff have shown the

highest capacity additions in the last years (Germany and Spain had the highest value in 2008 making up 72% of the total added capacity in Europe) [BWE09]). Some countries even swapped

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their central support instrument to Feed-In Tariff. For Vietnam a support scheme triggering huge capacity additions could help sat-isfying the fast increasing electricity demand and meet the gov-ernmental targets.

(5) As Vietnam has a well-developed grid system it is not necessary

to limit the new generation capacity (e.g. by tendering only a lim-ited amount of generation each time). Responsibility on the amount of capacity addition can be left to the (new) market en-trants.

(6) One crucial element of Feed-In Tariff systems - a standardized

Power Purchase Agreement with the grid system operator has al-ready been foreseen in the second Phase of the deregulation of the electricity sector.

(7) A well-tuned Feed-In Tariff will show a good balance between

cost-efficiency and project quality. In the short term Tendering Schemes seem to be more cost-efficient, but the competitive ele-ment has triggered unrealistically low bids leading to many pro-ject failures.

(8) Vietnam will not focus on immature, new technologies (e.g. wave

power, PV…). Well-proven and reliable technologies will be im-plemented first and preferentially. A Feed-In Tariff is the right tool to foster in this level of development.

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2. Existing Regulatory Mechanism of Vietnam The Government of Vietnam has recently begun to put in place a policy framework for renewable electricity development through the legal docu-ments as follows (in chronological order): • The Decision No.22/1999/QD-TTg of 07 August 1999 approved by the

Prime Minister on Approval of Rural Energy Projects has created the base for renewable energy use by stipulating that rural electricity supply will use national power grid and off-grid least cost based power projects. This Decision stipulates that the provincial people committees are re-sponsible for preparing power development plans as well as development and management of renewable energy. This decision also emphasizes that in some mountainous and island communes which have not yet been connected to the national power grid, the local authorities shall prepare plan for construction of local power plants suitably with concrete condi-tions of sites such as small hydropower, wind power or solar power pro-jects. The Government encourages economic sectors within and outside the country to be involved in investment of IPPs with capacity less than 5000 kW which are proposed to be approved by the provincial people committees or lower authority levels, depending on the investment scale. If the power project is connected to the national power grid, it needs to enter into a PPA with EVN.

• The Decision No. 825/QD-TTg of 20 September 2002 approved by the

Prime Minister on Comprehensive Poverty Reduction and Growth Strat-egy has elaborated all general objectives, institutional arrangements, policies and solutions of the 10-Year Strategy, of which, rural energy services is considered as a important solution for rural development and poverty reduction.

Relating to the decentralized rural electrification, and rural energy develop-ment, CPRGS gave clearly policy that:

• “For the communes that cannot access the national electricity grid (estimated to number about 200 poor communes), the Government will provide capital financing or extend concessional credits with zero interest rate to enable local people to develop their own self-supplying electricity plants, e.g. small-scale hydro-electricity plants, household generators or group of several households using other types of energy (solar energy, wind power, etc.)

• “Address the problem of women being overly burdened by domestic

work by investing in: small-scale technologies to serve family needs, rural clean water, and energy projects”.

• The Decree No. 102/2003/ND-CP of 03 September 2003 of the Govern-

ment on Energy Conservation and Energy Use approved by the Prime Minister establishes a broad regulatory framework for promotion of en-ergy conservation and efficiency. To encourage the businesses conserv-

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ing the fossil energy sources, one of measures the Decree specified that: “Promoting renewable energy resources to conserve the non-renewable energy such as coal, petroleum products and natural gas”.

• Decision No. 176/2004/QD-TTg of 05 October 2004 approved by Prime

Minister on Viet Nam Power Sector Development Strategy up to 2020 shows the Power Sector Development Strategy for the period 2004-2010, and orientation for the period up to 2020. Regarding the development orientation for renewable energy, the strategy states that:

• Renewable energy development in order to meet the electricity de-

mand in island and mountainous areas. • Suitable policies of electricity tariff should be set for facilitation of

power plant development in island and mountainous areas.

• Provide budget for electrification projects in rural, mountainous and island areas, aiming at economic development, hunger eradication and poverty alleviation for these areas.

• The Electricity Law No. 28/2004/QH11 issued on 03 December 2004 and

became effective on 01 July 2005, aims to attract domestic and foreign investors, ensure equality, fairness and competition in power production and trading, and protect legal rights and the interests of consumers. Re-garding the development of renewable energy resources, Electricity Law states that “Strong motivation to exploit and use of renewable sources to generate electricity” (Article 4, Clause 4). Vietnamese Government has encouraged the domestic and foreign investors to invest in renewable electricity projects by the policies below:

• “Investment projects of developing the power plant using the renew-

able energy sources will enjoy the preferential investment, electricity tariff and taxes according to the guidance of Ministry of Finance” (Ar-ticle 13, Clause 1).

• “Encouraging agencies and individuals in construction investment of

electricity grid or power stations using the power on the spot, renew-able power in order to supply electricity to rural, highland and island areas” (Article 60, Clause 4).

Government’s Subsidy Policies stipulated in this law consisting of: Subsi-dizing the investment capital, Subsidizing the loan interest rate of invest-ment capital, Preferential tariffs and taxes. The Ministry of Finance also coordinated with Ministry of Industry in directing the implementation of these subsidy policies to attract domestic and foreign investors in power production and trading. However, specific preferential policies to encourage the investment and development of renewable energy sources for power generation are not still developed except renewable energy CDM projects which were regulated separately in the Decision 130/2007/QD-TTg.

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• Decision No. 1855/QĐ-TTg of 27 December 2007 on National Energy Development Strategy of Viet Nam up to 2020, and Outlook to 2050 was approved by Prime Minister. The development orientations related to renewable energy is given in the National Energy Development Strategy as follows:

• Renewable energy will contribute to mitigating environment impacts

caused by its development, as well as minimizing greenhouse gas emissions.

• Priority development areas: 1) Hydropower and wind-power projects

and utilizing agricultural by-products and wastes for electricity gen-eration, 2) Utilizing solar energy for heating, drying agricultural prod-ucts, filtering water, etc. in services, public, households and agricultural production, 3) Biogas for cooking in rural areas.

• Priority is given to development of renewable energy with increase

rate from negligible share at present to about 3% of the total commer-cial primary energy, equivalent to 1.4 million TOE in 2010, to about 5% in 2020 and about 8 % of the total commercial primary energy, equivalent to 9.0 million TOE in 2025, and 11%, equivalent to 35 mil-lion TOE in 2050.

• The share of renewable electricity in power generation shall account

for 3% in 2010, 5% in 2020 and 10% in 2040.

To achieve the targets above, the solutions on policy including:

• Investigate and evaluate new and renewable energy potential, make integrated planning on utilizing new and renewable energy.

• The State provides financial support and tax exemptions for program

on investigation, research, trial manufacture and establishment of pilot locations using new and renewable energy.

• Select the technology suitable to Vietnam’s conditions, promptly ap-

ply for livings, especially in rural and mountainous areas.

• Coordinate new and renewable development program with other pro-grams in rural areas such as rural electrification, forestation, poverty-alleviation and cleaning water programs.

• The Decision 130/2007/QD-TTg of 02 August 2007 approved by the

Prime Minister on mechanisms and financial policies for the projects invested according to CDM stipulates that all the domestic and foreign investors invested in renewable energy projects can get the preferential treatments such as import tax exemption, land fee exemption, investment preferential credits and other supporting budget for preparing CDM pro-ject documents.

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• Inter – Ministrial Circular No.58/2008/TTLT-BTC-BTN&MT of 04 July 2008 on guiding implementation of some articles under Decision No. 130/2007/QD-TTg of the Prime Minister on mechanisms, financial policies on CDM projects provides guidelines for collection, manage-ment, and use of Certified Emission Reductions (CERs) selling fee, man-agement of CERs resulted from CDM projects using ODA funds, the calculation method of subsidy rate for one unit of production, and sub-sidy policies to products of CDM projects. Beneficiaries from CERs granted or CERs owner have to report to Ministry of Natural Resource and Environment (MONRE) and register with Viet Nam Environment Protection Fund (VEPF) about contact details for CER receipted, quan-tity of CER granted, and the share among relevant investors to a CDM project. Rate of CERs selling fees (from 1.2% to 2%) of total income which is get from CERs selling in accordance with the signed contract (or CERs’ quantity which is transferred to home country by foreign in-vestors) will be paid to VEPF. For projects invested by State budget or ODA, CER selling fee must be left in full at VEPF after deducting ex-penses of CER selling (if any). All CERs selling fees paid to VEPF will be used for covering expenses such as supporting public awareness rais-ing in relation to climate change and CDM, supporting process of CDM project document approval, management and supervision of CDM pro-jects, preparation of CDM project documents etc. The products of CDM projects enjoyed subsidy policy from Vietnam Environment Protection Fund (VEPF) are electricity that is produced from renewable energy such as wind power, solar, geothermal energy est. Subsidy options are deter-mined based on the results verified by VEPF that actual producing costs for each unit are higher than actual selling price in the signed contract.

Subsidy level for each product unit is based as follows:

Subsidy level for each product unit = Actual producing

costs for each unit + Planned profit /each unit - Actual selling price

for each unit

In which: • Actual production cost for each unit is defined as an eligible and reason-

able cost to calculate taxable income in compliance with regulations on corporate income tax issued by Ministry of Finance.

• Planned profit for each unit is calculated yearly by Investor and is

submitted to VEPF to conduct appraisal. Finally it must be submitted to Management Committee of Fund for official decision. The calculation of planned profit is based on profit of same product type and is not higher than average profit of the product.

• - Actual selling price is the actual price at the payment time. Vietnam Environment Protection Fund will determine subsidy policy to products of CDM project basing on the appraisal results of price option, planned profit which are received official decision and submit to Manage-

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ment Committee of Fund for reviewing, decision of subsidy policy for each unit of each project. The yearly subsidy amount is calculated by:

Yearly subsidy amount =

Subsidy level for each unit in respective year

x Quantity of products sold in respective year

- Actual incomes from CERs selling are allocated in respective year (if any)

In which, actual incomes from CERs selling (if any) which are allocated in respective year are an income from CERs selling (if any) less (-) payable CERs selling fee and relevant CERs selling cost (if any) allocated in respec-tive year. • Ministrial Circular No.18/2008/QĐ-BCT of 18 July 2008 on issuing the

stipulations on tariff of avoided costs and SPPA for renewable energy power plants has been issued by Ministry of Industry and Trade. Avoided cost calculated in this tariff is the cost to produce 1 kWh from generation unit with highest production cost in national electricity system that the local power agencies can afford to buy electricity from outside genera-tion source instead of their self-investment, generation and transmission to the consumers. The annually tariff of avoided costs is calculated by Electricity Regulatory Authority of Vietnam (ERAV) that classified ac-cording to dry and raining seasons in year and different regions, and peak, normal and low hours of the day. The avoided cost tariff of 2009 for small renewable energy power plants calculated is presented as fol-lows:

Dry season Raining season

Peak hours

Normal hours

Low hours

Peak hours

Normal hours

Low hours

Surplus energy

Northern 435 419 415 483 472 470 235

Middle 403 411 418 418 427 439 220

Southern 428 427 426 453 451 447 223

Capacity cost (for all regions)

1,674

Table 2-1: Electricity Tariff (VND/kWh) The issuing the tariffs of avoided costs and SPPA is a initial effort to gradually develop a competitive power market. However, the avoided costs calculated are still too low to encourage renewable energy projects except the small hydro power plants. Therefore, it needs to have the preferential

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measures on finance and investment for other sources of renewable energy such as wind power, solar energy ect. • Proposed Strategy for Renewable Energy Development in Viet Nam

to 2015 and outlook to 2025 have been completed in July 2009 by Insti-tute of Energy and is being waiting for approval by the Government of Viet Nam. The proposed strategy focused on support for investment and development of renewable energy projects as follows:

• The provision of investment license and grid-connection services shall

be made in accordance with the regulations of Government on invest-ment project management.

• Electricity generated from qualified grid connected renewable energy

producers will be purchased by the distribution companies under the avoided cost tariff published annually by MoIT.

• Qualified renewable energy producers will benefit from the non-

negotiable standardized power purchase agreement published by MoIT, subject only to the technical requirements of the grid code.

• The proposed Renewable Energy Development Fund will provide

subsidy to qualified grid-connected renewable energy projects subject to a maximum subsidy. Such subsidies will be awarded by transparent competitive solicitation that is consistent with the market principles set by the Electricity Law.

• The Government encourages and subsidizes investment in develop-

ment of off-grid renewable projects to support the income generating activities and to improve living standards in remote rural areas where the national grid can not be reached. The main criterion for award of subsidy for off-grid schemes is a demonstration of financial viability, the standards for which will be set by Renewable Energy Develop-ment Office (REDO).

• The Government will provide assistance to the poorest areas to assist

them with preparation of financially viable off-grid electrification schemes.

• The Government will promulgate lifeline tariff rates for off-grid

schemes for a minimum quantity of electricity to provide even the poorest households access to affordable electricity.

• In cases where off-grid schemes require continuing subsidy (as is

likely for Island mini-grids powered by diesel-PV-wind hybrid sys-tems), the Government shall provide subsidy for project operation to preserve equity between such areas and the areas served by the Na-tional Grid, whose rural customers enjoy a nationally imposed tariff ceiling.

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• The natural resource tax on renewable energy projects should be

waived. The related legal documents above have shown the Viet Nam Government’s commitment to the promotion of renewable energy. In general, there are no specific incentives for each type of renewable energy source on investment capital, loan interest rate of investment capital and preferential tariffs except Inter – Ministrial Circular No.58/2008/TTLT-BTC-BTN&MT and Minis-trial Circular No.18/2008/QĐ-BCT. However, to get the subsidy from Inter – Ministrial Circular No.58/2008, the projects must be CDM projects that have to follow the long process stipulated by international commitments and there is only a little renewable energy projects which can get CERs to have subsidy mechanisms stipulated by Inter – Ministrial Circular No.58/2008. In addition, when the electricity market is established, which is planned to start from 2009 as part of the electricity sector reform, each power produc-ing company will be put in a competitive environment, therefore, the Government is expected to compile and issue a Decree on Renewable Energy Development soon to guide the relating individuals and organiza-tions to effectively implement the Electricity Law and other related legal documents.

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3. Project Qualification Criteria Different eligibility criteria on wind power plants3 can be introduced for guiding the deployment of wind power to certain directions and avoiding undesired effects. However, as a general rule the deployment should be as unrestricted as possible to make best use of market forces triggered by the feed-in regulation. Any kind of restriction may hinder technical progress and may lead to higher costs than in the unrestricted case. This section describes possible criteria and their reasoning, reports international experi-ences, discusses pros and cons with these criteria against the particular conditions of Vietnam and give recommendations.

3.1 Size categories

Within the regulation, a restriction of size categories can be placed on either overall installed capacity of wind power plants or the size of each individual wind turbine. Furthermore, size restrictions can be applied where the tariffs are only paid below or/and above a certain threshold of installed capacity. The limitation on maximum installed capacity guides the deployment to a greater number of individual plants avoiding that a limited number of very large wind power plants will be installed. By this, one may avoid problems with public acceptance of wind power plants as they occur more frequently with large plants than with small plants. A requirement on minimum size would prevent small scale projects which would create high administration costs. In comparison to other feed in laws the handling regarding restrictions in wind plant size is diverse. While for example, Slovenia, the proposed new British framework and Sri Lanka consider size categories, Spain, Germany and South Africa do not apply plant size restrictions for wind energy. In Sri Lanka for example, the tariff applies only to projects not greater than 10MW. In Vietnam, deployment of wind energy is at the very beginning. Thus there is no experience on the public acceptance of this technology. In developed countries the public is mostly concerned on the visual impact of wind power plants. For Vietnam we do not expect similar concerns among the general public wind power but on the contrary a positive image of wind power standing for modern energy supply without pollution. However, the visual impact of wind power plants may play a larger role in places with tourism business. Studies have shown different attitudes of tourists towards wind power plants: For some, wind power plants a sign for an environmental benign energy supply salving their conscience. In this way, tourists would be even attracted by wind power plants. Other tourists perceive wind power plants as disturbing in pristine areas. In any case, we recommend governing

3 We define wind power plants as consisting of one or more individual turbines. Thus wind power plants may take the form of a wind farm with several turbines but may be just a single turbine.

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the size of wind power plants for reasons of public acceptance by restric-tions in building codes for specific areas where appropriate. Even though the Vietnamese power grid is generally assessed to be feasible to accommodate the targeted wind capacity of 500 MW without the need for grid enforcement4 very large wind power plants with say a capacity of more than 100 MW at one spot may require extra investments in grid infrastruc-ture. To avoid the need for these extra investments, one may introduce a cap on the maximum size. Additionally, our cost calculations for setting the wind tariffs are based on the assumption of a wind power plant of 30 MW as a typical feasible size. Very large wind power plants would be able to realise excess income with a uniform tariff since economies of scale exist with erecting and operating wind power plants. For a robust deployment of wind power in Vietnam it is advisable to have a greater number of individual projects rather than a very few large projects to allow for more wide-spread learning and to reduce the risk of failure. We therefore recommend to introduce a cap on the maximum size of wind power plants. For the sake of consistency with the existing regulation5 we recommend to set the cap at the level of 30 MW. The cap itself and the level of the cap should be reviewed once the target of 500 MW installed wind power plant capacity will have been surpassed. Small wind turbine may be regarded as particular favorable since they are feasible also for remote places and for smaller investors allowing them to generate income also in remote communities. We thus do not recommend implementing restrictions on the minimum size of wind power plants within the feed in tariff. The challenge of higher specific administrative costs of small wind power plants in comparison to large plants may be better ad-dressed with simplified Power Purchase Agreements for this category of plants. In summary, we recommend to implement a cap on the maximum size of individual wind power plants at a level of 30 MW subject to review once the target of 500 MW wind power capacity will have been achieved.

3.2 Minimum specific power yield

A requirement can be set on the minimum specific power yield. A certain level of annual full load hours, of the capacity factor, or of the yield at the site compared to a yield on a reference site can be required. The wind power project developer would have to prove ex-ante (i.e. before operation of the plant) the fulfillment of the requirement through an independent certificate. By this, wind power plants on sites with inferior wind conditions can be excluded ensuring that the erected wind power plants really will deliver power to the grid. With wind power plants erected at sites with low wind

4 In a meeting on 29 June 2009 EVN Renewable Energy Unit confirmed that 484 MW installed wind capacity can be feed into the grid without the need for overhauling the power grid.. 5 Decision No. 18/2008/QD-BCT of the Ministry of Industry and Trade, dated July 18,2008

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speed there is the risk that the public perception of wind power technology is spoilt. It has to be considered, that it is in the genuine interest of wind power project developers to erect plants only on sites with favorable wind conditions to maximize their profit and avoid financial losses. So the feed in tariff provides inherently already a strong incentive to exploit only feasible sites with good wind conditions, if tariffs are set appropriately. While South Africa does not set a minimum energy yield, Germany does, however in a particular approach. The experience from other feed in laws shows that the determination of a minimum energy yield through stated annual full load hours can be easily manipulated. This happens by installing a greater power generator but using a name plate with a false and lower capacity of the generator. Since the name plate capacity is not standardized this is not unlawful. For this reason the German Renewable Energy Law compares the envisaged power yield at the individual site with the power yield the plant would have achieved in a pre-defined reference site. This reference yield is part of the certification of any wind turbine and is dis-closed by all wind turbine manufacturers. German law requires that wind power plants need to achieve at least 60 percent of the reference yield to gain eligibility for remuneration according to the law. Also India’s new regulations will vary the tariff for wind energy based on resource intensity. They specify the capacity factor, to be used in four bands of wind power density in W/m². Unlike Germany where many high potential locations are already used by wind farms, Vietnam features still high and hardly used wind energy potential. Many locations with high wind energy potential are available. Thus it is very unlikely that project developers would go for inferior sites. We thus do not recommend setting requirements on the minimum power yield within the feed in tariff. This may come subject to review once the most attractive locations will have been exploited in order to avoid using areas with poor potential for wind power generation.

3.3 Contribution to provision of power for the electricity supply system

Wind power may enhance the performance of the electricity supply system beyond the pure probalistic delivery of kilowatt hours. Reliable forecasts on electricity e.g. lead to better load management for all grid connected power plants. The availability of wind power could be also enhanced by installing power storage at the plant so that a certain minimum power can always be delivered.6 In addition, wind power plants can contribute to grid stability and security. In countries where much wind energy gets fed into the grid or in areas where grid stability is rather low, voltage- and frequency regulation 6 However, power storage at the wind power plant is usually regarded as the most costly way to integrate probalistic wind power into the grid. Experiences show, that the existing power grid – if in a good state – can easily absorb some percent of wind power without any additional means. The wind power can be regarded as a negative load reducing the load profile. And even with higher shares of probalistic power generation, central storage and central control is much more effective than decentral means at the individual power plants.

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supported by wind power plants are of particular importance. Grid security and stability can be achieved through different technologies, e.g. application of synchronous generators. Such features cause additional costs to wind power plant developers so that they will not implement such technologies if not required by law (or power purchase agreement) or if not additional incentives are provided. Furthermore, wind turbines from the second market might be a very viable and inexpensive option in Vietnam. Used wind turbines are available on the international markets arising from repowering done in other countries. In general, these wind power plants are also not provided with grid stabilizing technologies. The German Energy Law provides a bonus for wind power plants equipped with grid stabilizing technologies. The bonus covers the additional costs for these voltage- and frequency regulation provisions. Criteria which oblige project developer to make contribution to provision of power for the electricity supply system can hinder the market entry of domestic manufacturers, deployment of used inexpensive turbines, and slow down the renewable electricity deployment. So we do not recommend to establish technical requirements on forecasts or minimum constant loads within the feed in tariff. Such stipulations should be subject of the Standard Power Purchase Agreement, if at all. In this regard, the grid operator may provide additional incentives for reliable, predictable power supply in case he might it less costly than balancing the power with the existing coal fired and hydro power plants. These provisions are subject to review once substantially higher shares of probalistic power generations (> 5 -10%) are accommodated in the Vietnamese power grid.

3.4 Required technical availability

The technical availability of a wind power plant describes the share of time the plant would be ready to supply power – irrespectively whether the wind blows or not. The technical availability thus describes how often the plant is out of order due to technical failures. The higher the quality maturity of the plant and the operation, the higher is the technical availability. The higher the technical availability the higher is the power output other things being equal. A requirement on a high availability of the wind power plant (say 97 %) would urge developers to install high quality equipment. Therefore, the developers would install state of the art turbines from manufacturers with good reputation and enough references. On the other hand, such requirements would create a barrier for domestic manufacturers since as newcomers they might be not able to reach high availability from the start. This would hamper local or regional companies to develop own wind turbines. There is a trade-off between availability and generation costs. Wind power plant developers will seek to find the optimal combination of high technical availability and low investment and generation costs to maximize their profits under a feed in tariff. Once the plant is installed, plant operators will seek to maximize availability to maximize output and thus income. So the

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feed in tariff itself already provides strong incentives for a high technical availability. We thus do not recommend to include any availability criteria in the feed in regulation. However, in case a certain level of availability is desirable from the grid system point of view these requirements should be included in the standard PPA rather than in the regulation. This would allow the purchaser of the power to monitor constantly the technical availability. The case that certain wind power plants frequently do not reach the required availability would be than regarded as a breach of contract allowing to terminate unilaterally the PPA.

3.5 Criteria for reviewing technical feasibility

Wind power plants need to meet technical and safety standards to ensure that humans and things are not harmed. Generally, countries or regions have their own rules that apply to all electricity generators, and also wind power generators have to comply with them. Moreover, there exists a wide range of international standards ensuring the quality of power supply in general and of wind power plants in particular. For instances, the International Electrotechnical Commission (IEC) has published standards for several renewable technologies. Currently they are preparing a certification scheme for wind turbines. Also in Vietnam an eligible wind power plant shall meet the safety and technical standards set down by the relevant standard body, Ministry or other official body (e.g. grid code). In addition, international recognized standards and codes shall be applied in their latest versions (e.g. ISO; IEC; ANSI; BSI; DIN; EN; JAPS). Since a feed in law is responsible for setting framework conditions and establishing feed in tariffs for renewable energies rather than stipulating technical details it is recommended to stipulate the technical standards for wind power plants in the standard PPA. This is common practice in many countries. It allows a better monitoring whether the requirements are fulfilled.

3.6 Criteria for reviewing economic feasibility

Analyzing the economic feasibility of a wind power plant allows to assess the profitability over the life-time of the power plant. A wind power plant will only supply power over its entire lifetime if the income from the feed in tariff is sufficient to cover capital and operating costs. To ensure that only economical viable projects are implemented one may oblige project devel-oper to disclose the economic feasibility of the project. One need to point out that it is in the very interest of the wind power plant operator that the wind power plant is economical viable because otherwise he will loose money. So one can assume that in general only projects which

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developers are assessing to be economical viable ex-ante will seek eligibility for the feed in tariff. Project might be reluctant to disclose confidential economic calculations since they might be afraid that competitors may use these data to their advantage. Also the chance that a wind power plant is not supplying power at all due to a wrong economic assessment ex-ante is very low. With wind power plants featuring low operating expenses power generation will always generate a marginal return. It is recommended to integrate a review of the economic feasibility in a Renewable Energy Regulation as the Decision No. 18/2008/QD-BCT stipulates in Article 8: “One power plant which has enough conditions can apply the avoided cost tariff. When carrying out the economic and financial analyses of the project, the regulation of electricity price framework “Temporary regulation on contents of calculation of economic, financial analyses and electricity tariff frame work for power generation plants” promulgated along with the Decision No. 2014/QD-BCN dated 13 June 2007 by Ministry of Industry and Trade and other documents replacing that Regulation has not to be complied with.”

3.7 Maturity of wind power plants

In the early phases of deployment of wind power in Vietnam it is crucial that wind power plants are installed which are supplying power in a reliable manner. Otherwise, there is the risk that the trust in this technology is spoilt so that no further deployment will take place. In general, one may assume that mature types of wind turbines i.e. those with a minimum amount of installed capacity worldwide will be more reliable. For this reason one may introduce a requirement that only turbines are eligible of which more than say 20 have been erected world wide. On the other hand, such criterion would limit competition and deny market entry of new or improved tech-nologies. One needs also to consider that it is in the very interest of the plant operator to run reliable turbines since otherwise he would loose money. In other countries it is not common practice to establish requirements on the maturity of the wind power plants in their Renewable Energy Laws. It is not recommended to introduce any minimum threshold how many turbines of a certain type must be installed before they are eligible for the feed in tariff.

3.8 Share of local manufacturing

The deployment of wind power plants lead to extra costs compared to fossil fired or hydro power plants. One may achieve a higher public and political acceptance if the domestic industry benefits from these extra expenses through supply of parts and entire turbines. A stipulation requiring a certain share of local content in the wind power plants erected would ensure such

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effect. It would help to promote the establishment of domestic wind power plant manufacturing creating income and employment. On the other hand, such requirement on local content may cause higher costs of wind power deployment compared to a situation without a local content requirement because the domestic industry in its infancy might be not able to supply turbines at internationally competitive prices. One may also encounter more immature turbines with lower performance. With a lack of international competition, the domestic manufacturers may not progress sufficiently their technologies. Further on, it is not clear that the domestic manufacturing capacities can be ramped up sufficiently fast to meet the fast growing domestic demand. The Vietnamese market framed by the target of 500 MW wind power installed by 2020 might be also not perceived as sufficiently large in the view of international wind turbine manufacturers to justify a domestic production of turbines. There are countries which has implemented such criteria. China for example regulates that 70 per cent of wind power equipment should be from domes-tic companies regardless of the source of funding (Mendonca, 2007). This helped to establish a lively Chinese wind power industry now also starting to supply international markets. In a single call for tender Portugal tendered out 1200 MW of wind capacity. The focus of the assessment of the tender was on how much of the power plants would be manufactured in Portugal. As a consequence an integrated manufacturing base for wind turbines could be established now serving more and more international markets. The Canadian province of Quebec published a similar call for tender some years ago. However, such stipulations are very controversial on international markets. Such stipulations might be not acceptable for the WTO since they hinder international competition. For Vietnam’s target of about 500 MW installed capacity by 2020 the market is too small to establish a domestic wind turbine manufacturing industry covering the entire value added chain. Thus we do not recommend to establish such requirements. However, this recommendation is subject to review in case Vietnam will substantially increase the target of installed capacity. If local content requirements are considered than WTO regulations have to be taken into account.

3.9 Ownership restrictions

One may restrict eligibility to those wind power plants which are owned by certain types of owners. For instance, one may exclude international inves-tors or restrict the share of international investments in individual plants. Considering that the Vietnamese power market is not liberalized and features a strong incumbent utility one may establish favorable conditions for Independent Power Producers (IPP) running wind power plants. Or one even may grant the feed in tariff exclusively to IPP excluding the incumbent EVN. IPPs have been crucial for driving the deployment of renewable energies in many countries particular in the early phase of market introduction. IPP

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implementing renewable energy plants often have renewable energy as their sole focus. So it is in their very strong interest to drive the deployment process of renewable energies. In contrast incumbent utilities are often hesitant to invest in renewable energies. Incumbent utilities may regard investments in renewable energies as a threat to their existing facilities by devaluating these existing stakes. For this reason, they might misuse their role as grid operator to hinder deployment of individual wind power projects through slowing down the process of grid access and others. Moreover, incumbent utilities might be not well prepared to erect and operate decen-tralized wind power plants since they usually run large scale fossil fried power plants. Finally, the exclusion of EVN would strengthen competition in liberalized power markets because new actors in form of IPPs will enter the market. On the other hand, such utilities have usually a strong financial power allowing them to free sufficient monies to finance a fast deployment of wind power. The processor of the German Renewable Energy Act, the Feed-In Law of 1991, excluded utilities from eligibility for the feed in tariff. It was argued that the existing regulations in the then deeply regulated power market would allow recovering any kind of investments anyway so that no particu-lar scheme would be needed for the utilities. This stipulation was abandoned with introduction of the Renewable Energy Act since deployment of wind power and other renewable energy technologies had very much advanced so that they did not need any more special support in this respect. Moreover, it was felt that this stipulation did not fit into the concept of competitive power markets. EVN as the incumbent utility of Vietnam has set up a business unit exclu-sively dealing with renewable energy plants. In the absence of appropriate regulations, however, they have not invested in wind power so far. At this very point of time, EVN seems not to raise risk to the deployment of wind energy or IPP market entry in Vietnam. So we do recommend to leave the feed in tariff open to any type of investor. However, if difficulties for IPPs with market entry arise, it is suggested to exclude EVN from the eligibility of the fee in tariff for a limited period of time, say 5 years, to allow for a head start of IPPs.

3.10 Used vs. new turbines

Eligibility of plants can be restricted to those which exclusively use new wind turbines. Or it is disregarded whether new or used turbines are in-stalled. There is a growing international market for used wind turbines. Existing wind power plants are “repowered” i.e. existing turbines are replaced but larger turbines to increase the absolute yield at a given site. Thus, these turbines are neither necessarily worn out nor is the used tech-nology out dated. Thus used wind turbines might be an inexpensive option for wind power deployment in Vietnam. There are several disadvantages incorporated with the eligibility of used plants: Local manufacturing is less triggered to the same extent since local turbines of potentially not the latest technology will compete directly with used turbines. Thus investment costs

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might be low but operating costs might be higher due to higher maintenance costs. Operators of used wind turbines may realize excess profits since the calculation of the tariffs is based on new wind turbines. However, this negative impact can be avoided by granting lower tariffs to used turbines than to new turbines. Used wind turbines will not last as long as new turbines so potentially they will be decommissioned before the end of the remuneration term. Thus the total power generation of used turbines will be less than the one from new ones with the effect that total contribution of used turbines to power supply over the life time in Vietnam is less than the one from new turbines. Internationally, we could not find any restriction on the eligibility of used wind turbines. We assume that policy makers regard used turbines not as an issue, particularly since the market for used turbines is a rather new phe-nomenon. Weighing the above mentioned arguments for the case of Vietnam, we recommend to introduce some restrictions on used wind turbines in the feed in tariff. Only wind turbines younger than 10 years should be eligible to avoid outdated technology and leave sufficient operation time in Vietnam. We further recommend to reduce the granted tariff for used turbines by 20 % compared to the generic tariff for new turbines to reflect the lower costs of used turbines. A In the unlikely case, the Vietnamese market will be flooded with used wind turbines displacing new turbines one new to revisit this recommendation. A related question is whether wind power plants which already exists in Vietnam will be allowed to opt into the feed in tariff. At the moment only one large wind power plant exists in Vietnam. Since existing framework conditions has been obviously sufficient to trigger the investment in the wind power plant one may argue no additional support through the feed in tariff is needed. However, exclusion of existing wind power plants from the feed in tariff would put any ongoing deployment to a halt. Investors would better wait for the introduction of the feed in tariff and then start their venture. This is certainly a problem of transition, so we recommend that with the feed in tariff is to be applied also to all wind power plants commis-sioned three or less years before the feed in law will come into force. The duration of the feed in tariff payments might be shortened by the time which the plant has been already remunerated through other means.

3.11 Spatial restriction

The regulation should clearly state that it only applies to wind power plants sited in Vietnam and feeding into the Vietnamese grid are eligible for the feed in tariff. By this it is clarified that plants which are based outside of Vietnam, but supplying electricity into Vietnam are excluded from the feed-in tariff. Within Vietnam, one may exclude certain sites for the risk of Typhoons. However, these risks should be born by the developer who either will avoid

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regions with typhoons at all or will apply typhoon proven wind turbines. Thus the feed in tariff does not need to address the issue of typhoons. In highly developed electricity markets with larger and more established renewable energy sectors, more complex feed-in tariffs are appropriate. Once more electricity from renewable energy sources get fed into the grid, some of the above mentioned issues can be considered in the second phase, building on the lessons learned from the initial phase.

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4. Evaluation Criteria for License Applications Up to now, there are no regulations on criteria for evaluating the license applications of wind power plants in Viet Nam, although these ideas could be found preliminarily in some other related legal documents. In the follow-ing we review these documents. Then we identify potential obstacles hindering the deployment of wind power. Finally we provide recommenda-tions for criteria on license applications.

4.1 Investment Law No.59/2005/QH11

This law passed on 29 November 2005 by the XIth National Assembly of the Socialist Republic of Vietnam at its 8th session provides for investment activities for business purposes; rights and obligations of investors; assur-ance of legitimate rights and interests of investors; investment encourage-ment and preferences; state management of investment in Vietnam and offshore investment from Vietnam. There are four forms of investment regulated by the investment law consisting of Business cooperation contract (BCC); Build-operate-transfer contract (BOT); Build-transfer-operate contract (BTO); and Build-transfer contract (BT). Regarding the investment domains, these are three domains regulated by law, consisting of preferential, conditional and banned from investment. Conditional investment domains include: • Domains, which affect national defense, security, social order and safety; • Financial and banking domains; • Domains, which affect public health; • Culture, information, press and publishing; • Entertainment services; • Real estate business; • Survey, prospecting, exploration and exploitation of natural resources;

ecological environment; • Development of education and training. • Some other domains as provided for by law. For the investment policies, the State shall treat equally before law investors of all economic sectors, as between domestic investment and foreign investment; shall encourage and create favorable conditions for investment activities. Moreover, the State shall encourage and adopt investment prefer-ential policies for domains and geographical areas entitled. New and renew-able energy technologies are one of the domains that can get preferential treatment including preferential tax rates, land use and other supports if investors implement any form of investment stipulated by law. Thus, renewable energy technologies can get preferential tax rates, land use and other supports if these are within forms of investment: BCC, BOT, BTO and BT. Investors can choose and implement any form of them. In order to manage investment under planning, all investment projects must comply with other plans on technical infrastructure, land use, construction,

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use of minerals and other natural resources. Competent state agencies in charge of planning shall have to announce on the mass media plans related to investment activities. Regarding the investment license applications, the investors need to register the investment projects that must be on the list of investment projects or conform with the master plan. The investment dossier consists of the reports on financial capability of the investor, the techno-economic explanations with details on investment objectives and location, land use demand, investment scale, investment capital, project execution schedule, techno-logical solutions and environmental solutions. With regard to investment projects not yet included in the master plan, the state agencies in charge of investment shall act as major agencies in working with competent state agencies in charge of plannings to consider and reply investors within 30 days after receiving their requests. For foreign investment projects capitalized at under VND 300 billion each (about $16.5million) and falling outside the list of conditional investment domains (This means the domains where investment shall only be permitted under specific conditions stipulated by law), investors shall fill in the investment registration procedures at provincial-level state agencies in charge of investment in order to be granted investment certificates. How-ever, for projects with large investment capital (at VND 300 billion or more), the process must go through examination procedures in order to be granted investment certificates. For national important projects, the National Assembly shall decide on investment undertakings and provide criteria for projects, the Government shall stipulate the order and procedures for investment examination and grant of investment certificates. The time limit is 15 days for provincial level state agencies to grant invest-ment certificates to foreign investment projects providing the agency has received complete and valid investment registration documents. The time limit is longer (up to 45 days) if the project is above VND 300 billion or is on the list of conditional investment projects.

4890S11/FICHT-5530494-v1 4-1

4.2 Decision No: 30/2006/QD-BCN

Regarding the investment licensing the Decision of 31 August 2006 ap-proved by Minister of Industry on the regulations on investment and con-struction management applicable to independent power projects stipulated that: • IPPs (Independent power projects) shall be invested in the forms of

build-operate-transfer (BOT), build-own-operate (BOO) or other forms as provided for by law.

• Investments in IPPs must conform to electricity development plans

approved by competent agencies. Projects not yet included in such plans must be approved by agencies with planning-approving competence be-fore their investment preparation is made.

• The competence to approve electricity development plans shall comply

with the provisions of the Electricity Law. For plans on small-sized hy-dropower plants, the Ministry of Industry shall approve the national planning while provincial People's Committees shall approve their local plans after consulting the Ministry of Industry.

• Agencies competent to license investment in IPPs are those designated

under the law on investment and construction management. For the selection of investors • In order to ensure the efficiency and sustainability of projects, the

selection of investors for execution of IPPs shall be carried out through bidding.

• For special cases such as small-sized projects; projects aiming to supply

electricity for deep-lying and remote areas and difficulty-hit areas; pro-jects for which there is only one registering investor or for other plausible reasons, agencies competent to license investment shall decide on the selection of investors through appointment of contractors.

For the registration to participate in investment projects, organizations and individuals that register for investment in IPPs shall have to make and submit to competent agencies investment reports, for group-A projects (with investment capital over 1500 billion VND) or investment application reports, for group-B (with investment capital from 75 to under 1500 billion VND) and group-C projects (with investment capital under 75 billion VND) for the latter to permit investment research and then investment. The investment reports and investment application reports submitted to investment licensing agencies shall comprise:

4890S11/FICHT-5530494-v1 4-2

• For group-A projects: Investment reports shall be compiled in accordance with legal provisions on management of investment projects on the con-struction of works.

• For other projects:

• The investor's written request for making investment. • Basic information on the investor: Documents on the investor's legal

capacity, business registration, diagram of the organizational appara-tus, key personnel, project execution experience, and financial and technical capability, enumerating projects which the investor has exe-cuted (including industrial projects and power projects) over the past five years, and enterprise's settlement/audit reports of the last three years. The investor shall have to bear responsibility for the accuracy of declared information.

• Preliminary information on the registered project: Construction loca-

tion; project purposes; main parameters on the capacity, investment capital, time of commission, contents related to branch and local plan-nings, the estimated schedule for project execution, compensation volume, population relocation, and methods of investment manage-ment, operation, business and transfer of the project (if any).

• The written agreement on the purchase of electricity by the Electricity

of Vietnam or electricity wholesale or retail units.

• For projects falling beyond the competence of provinces, the written approval of the provincial People's Committee shall be required.

• Sources of capital to be mobilized for the execution of the project and

loan commitments of credit institutions or banks.

• The investors' capital must account for least 30% of the total capital. In special cases, this rate shall be decided by competent agencies but must not be lower than 20%.

For the appraisal and approval of investment projects: • Investors shall formulate, appraise and submit to competent agencies

basic designs for appraisal according to the provisions of law. • The competence to appraise basic designs shall be as follows:

• The Ministry of Industry: Group-A projects and projects with the main work located in two or more provinces.

• Provincial/municipal Industry Services: The remaining group-B and -

C projects.

4890S11/FICHT-5530494-v1 4-3

4.3 Decree No. 78-2007-ND-CP

A BOT contract is defined under the 2005 Investment Law and Decree 78 of 11 May 2007 approved by Prime Minister to stipulate the sectors, condi-tions, order, procedures and incentives applicable to investment projects for development of infrastructure facilities on the basis of build-operate-transfer (BOT), build-transfer-operate (BTO) or build-transfer (BT) contract as a contract signed between competent state authorities with investor(s) to build and operate infrastructure within a period of time. When that period expires, investor(s) shall transfer the works, without compensation, to the state. Under BTO contracts, investor(s) shall be given the right to operate the infrastructural work to the state. For the BT contracts, after build and transfer, the investor(s) shall be given favorable conditions to run other projects to recover their investment costs and earn profits. The Government encourages investment under the BOT, BTO, or BT contracts in construction, infrastructural operation, or renovation, enlarge-ment, modernization, operation and management of certain works such as roads, bridges, tunnels, railways, airport, sea & river ports, water supply factories, water drainage systems, waste treatment systems, power plants, power grids, and other infrastructures as decided by the Prime Minister. Decree 78 stipulates a number of significant incentives for investment projects under the form of BOT, BTO or BT contracts, including: BOT Enterprises and BTO Enterprises shall be entitled to corporate income tax incentives as stipulated in respect of projects included in the list of sectors entitled to special investment incentives. Incentives relating to corporate income tax rates applicable to such enterprises shall apply for the whole duration of implementation of the project. Tax exemptions shall be granted to the royalties generated from technology and intellectual property transfers if any. Exemptions shall be granted to land use fee or rental for the whole project life. The Government may designate guarantors for investors’ loan; and other supports are promised by the Decree during the project operation. Regarding the investment licensing: It is different from other models of investment where the licensing powers are mostly allocated to local authori-ties, Decree 78 states that all BOT, BTO, BT contracts must be appraised and licensed by the Ministry of Planning and Investment. If new incorpora-tion is proposed under the BOT, BTO, or BT contract, after obtaining the investment licence, investors shall apply for establishment of a company according to the provisions of the 2005 Law on Enterprises. The order of project investment is stipulated by Decree as follows: • Based on planning, guidelines for socio-economic development, minis-

tries, ministerial equivalent bodies or Government bodies and provincial people’s committees shall formulate and approve a list of projects calling for investment capital on the basis of BOT contracts, BTO contracts and BT contracts in their respective branches and localities.

• The list of projects shall be submitted to the Ministry of Planning and

Investment, relevant ministries or branches and the provincial people's

4890S11/FICHT-5530494-v1 4-4

committees of the localities in which the proposed projects will be im-plemented, for their opinions.

• The document seeking opinions specified the necessity, objectives,

location, designed capacity and proposed investment capital and mini-mum technical and financial requirements of the projects; and recom-mendations on an authorized State body and forms of selection of investors for project contract negotiations.

• The Ministry of Planning and Investment, relevant ministries or branches

and the provincial people’s committees of the localities in which the pro-posed projects will be implemented shall provide their opinion about the list of projects and the issues within 30 working days.

• Upon agreement with the relevant bodies, the ministries, branches and

the provincial people’s committees shall publish the lists of projects on the website of respective ministries, branches and localities and at the same time in three consecutive issues of central and local daily newspa-pers.

• Based on the published list of projects, the authorized State body shall

appoint a domestic or foreign consultant contractor to formulate a pro-posal for a project and tender invitation documents and then hold open domestic or international tendering for selection of the investor(s) for project contract negotiations.

In the case, an investor may propose on its own initiative a project other than those in the list of projects which is published they must prepare a proposal for the project. The proposal file for a project submitted to the authorized State body shall comprise the following items: (a) Proposal for the project containing the items specified in this Decree; (b) Document evidencing the legal status and the technical and financial

capacity of the investor; (c) Other documents necessary for explaining the proposal for the project. Where the proposal for the project conforms to the master plan approved by the authority, the authorized State body shall organize the collection of opinions from the relevant bodies and decide to approve the proposal for the project in accordance with the procedures specified in this Decree. Where the proposal for the project has not yet been included in the approved Master Plan for Renewable Energy Development, the authorized State body shall submit it to the ministry in charge of management of the relevant branch for consideration and addition to the master plan under its authority, or for submission to the Prime Minister for his approval of and addition to the master plan. For the evaluation and issuance of investment certificates, the Ministry of Planning and Investment shall be the core point to organize evaluation and

4890S11/FICHT-5530494-v1 4-5

issuance of investment certificates to projects. Procedures for evaluation and issuance of investment certificates shall be performed as follows: (a) An investor shall submit ten (10) sets of the file, including at least one

set of original copies, to the Ministry of Planning and Investment for evaluation and issuance of an investment certificate. The project file shall comprise:

• Project contract; • Investment project for construction of facilities and other projects (in

the case of BT projects); • Joint venture contract and charter of the project enterprise (if any); • Initial contracts relating to implementation of the project or prelimi-

nary agreements for purchase of raw materials or sale of products (if any).

(b) Within a time-limit of three working days from the date of receipt of the

valid file, the Ministry of Planning and Investment shall seek opinions from relevant bodies such as ministries, branches and provincial people's committees;

(c) Within a time-limit of fifteen (15) working days from the date of receipt

of the valid file, the bodies shall provide their written opinions about the project.

(d) Within a time-limit of fifteen (15) working days from the date of receipt

of the written opinions of the relevant bodies, the Ministry of Planning and Investment shall issue an investment certificate to the project.

4.4 Potential Barriers

From above analyses some potential barriers could be found during per-forming the evaluation and issuance of investment certificates: • Limitation of legal documents. The Investment Law and Decree 78 stipulate the orders on evaluation and issuance of investment certificates as well as incentives for investment projects of infrastructure facilities including power projects. • Lack of specific preferences for renewable energy development. One of importance criteria for issuing investment certificate is that project must achieve feasibility on economical and financial aspects. However, renewable energy alone can not be competitive with traditional energy types if there are no specific preferences stipulate by law. Thus causes difficulty on lending budget from banks and as well as receiving investment certifi-cates. Therefore, it is necessary to build a new decree on stimulation and

4890S11/FICHT-5530494-v1 4-6

development of renewable energy in which the very important articles on feed- in- tariffs and SPPA should be mentioned. • Limitation on institutional structures Up to now this is still no complete institutional structures at levels that have specific functions in order to evaluate, stimulate and support renewable electricity projects. This is an issue for licensing and may impact the development of renewable energy development. • Lack of criteria for evaluating the license applications. Renewable energy in general and wind power in particular are still initial steps in research and development in Viet Nam. These technologies are specific characteristics, therefore, a set of criteria for evaluating the license applications of renewable electricity projects as well as wind power plants in Viet Nam is necessary to support and guide the licensing authorities on evaluation and issuance of investment certificates. • Lack of adequate information on potential areas planned for development of renewable energy projects. Currently, information on potential of renewable energy resources and specially the specific information about wind energy sources such as the topographical characteristics of the area and wind characteristics are inade-quate. These cause difficulties for building the planning and strategy for development of wind power and then license applications. Proposal of evaluation criteria for license applications From above potential barriers, it is necessary to propose the principles and procedures applicable to the identification and use of wind energy resource areas as well as the establishment of technical criteria regarding license applications, with a view to ensuring efficient and effective use of wind energy for generation of electricity. Following are proposed evaluation criteria for license applications: Proposed projects must be in the list of projects in planning areas for wind power development. Referring to the Decree No. 78-2007-ND-CP, based on the master plan on renewable energy for socio-economic development, ministries, ministerial equivalent bodies or Government bodies and provincial people’s commit-tees shall formulate and approve a list of projects calling for investment capital. Therefore, the master plan on renewable energy or wind power must be completed to classify the categories of wind energy density in potential areas and propose the investment projects for which authority bodies at levels to formulate and publish the list projects. Based on the published list of projects, the authorized bodies shall appoint a domestic or foreign consultant contractor to formulate a proposal for a project and tender invitation documents and then hold open domestic or international tendering for selection of the investor for project contract negotiations. In the case, an investor may propose on its own initiative a project that is not among the list of projects published, the investor must establish and prepare updated data and other necessary procedures for licensing. After the submission of the

4890S11/FICHT-5530494-v1 4-7

updated data and necessary procedures from the investor, local authority or Government must approve update list and then the proposed project become eligible for development on track. However, anybody can apply with projects to be incorporated in the list. The project will automatically enter into the list two months after application if the application is complete and the authorities have not positively rejected the application with reasonings. Criteria for reviewing technical feasibility Firstly, a technical standard set on wind power technology must be set up by the relevant standard body as base for reviewing technical feasibility. The technical standard set must cover the identification of wind energy resource areas and applications to be filed for these areas, technical evaluation of license applications, control of project designs and construction supervision. • Identification of Wind Energy Resource Areas for which license applica-

tions • Authorized body shall propose Wind Energy Potential Areas (WEPA)

grouped according to categories of power density for license applica-tions. In case, investors propose wind power projects in areas outside WEPA which have not been filed with data on wind energy, license applications need to have data on wind measurements at least for one year to become eligibility.

• Authorized body shall publish on its website the map section of these

WEPA areas, power densities, reference installed power capacities and annual amount of electricity that can be generated with that in-stalled power capacity.

• Authorized body shall provide the legal entities willing to file license

applications using the WEPA areas with the information about the to-pographical characteristics of the area, wind characteristics, turbine coordinates, environmental, ownership, usage and transportation statuses, as well as the close vicinity of the area.

• Technical evaluation of license applications Of the applications being in WEPA, the authorized body shall forward to licensing body for reviewing technical feasibility. Following criteria are proposed for reviewing:

• Power plant areas: Applications whose power plant areas should not coincide with the area of other applications.

• The power density must be high enough to ensure the efficient and

effective use of wind energy for generation of electricity with feed-in tariff.

• Turbine location (coordinates): located turbine (coordinates) shall be

considered to make sure this turbine does not obstruct the wind of each other among the turbines located in the project’s area.

4890S11/FICHT-5530494-v1 4-8

• Control of project designs

• Total installed power capacity in the project design must be the same as the installed power capacity in the license.

• Turbines must not have been located on coordinates that may obstruct

the wind of the turbines of other applications or licensed legal entities.

• It must satisfy the criteria set out in the Regulation on the Designs of Electrical Installations.

• Project design control report, design approval and letter of compliance

shall be sent to the relevant authorized bodies. • Construction period supervision

• The legal entities must follow the approved project design. Any modi-fication during construction period shall be notified to relevant author-ized bodies.

Criteria for reviewing economic feasibility Normally, criteria for reviewing economic feasibility of traditional power projects consist of Economic Internal Rate of Return (EIRR), Net Present Value (NPV), Capital Recovery Time, and Benefit-to-Cost Ratio (B/C). For wind power projects, we recommend that an eligible feed-in tariff should be used to calculate EIRR, NPV, CRT and B/C for license applications.

4890S11/FICHT-5530494-v1 5-1

5. Calculation of the Levelised Electricity Costs This section is to describe the applied procedures, assumptions and simplifi-cations made for calculating an average value for the levelised electricity costs (LEC) for electricity produced from wind power in Vietnam.

5.1 Site selection and characterization

In the first step sites for wind power in Vietnam had to be selected, as-sessed, categorized and described mathematically. A mathematical descrip-tion of a wind site is mainly achieved using a special probability-function, giving a frequency distribution of the wind speed, and another formula setting the wind speed in relation to height. In general two different ap-proaches for describing a wind speed probability distribution are common: Weibull and Rayleigh distribution. The Weibull approach requires – besides the mean annual wind speed – knowledge about the so called “form factor” (‘k’) and the expectancy value7 (‘A’) of the wind speed.

K

AvK

eAv

AKvf

⎟⎠⎞

⎜⎝⎛−−

⋅⎟⎠⎞

⎜⎝⎛⋅=

1

)(

Equation 5-1 K: Form factor A: Expectancy value (m/s) v: Wind speed (m/s) vm: Mean annual wind speed (m/s)

The Rayleigh distribution which according to [IEH09] is a special case of the Weibull distribution (form parameter ‘k’ is set equal 2 for Central Europe as well as for Vietnam, [ECA07]) can be evaluated simply by the mean annual wind speed. In lack of data from Vietnam concerning wind speed distribution in the relevant heights for wind power the Rayleigh approach has been chosen8 for our calculations.

2

422

)(⎟⎟⎠

⎞⎜⎜⎝

⎛⋅⎟⎠⎞

⎜⎝⎛−

⋅⎟⎟⎠

⎞⎜⎜⎝

⎛= mv

v

m

evvvf

ππ

Equation 5-2 v: Wind speed (m/s) vm: Mean annual wind speed (m/s)

As the measurements where conducted in a height of 60m a correction formula setting the measurements in relation to the hub heights of the chosen reference wind turbines is to be applied. Most approaches need the “roughness length” (mostly named z0 in literature, depends on the terrain structure) as an input value. The roughness length is estimated with 0.05 m (Roughness Class 1, applicable for agricultural area with open appearance [HAU08]). The energy content of the wind increases with a power of three

7 The expectancy value is the wind speed with the highest probability. 8 The deviation between the two approaches has been determined to be max. 1,6% full-load hours.

4890S11/FICHT-5530494-v1 5-2

to the wind speed, hence towers ought to be as high as possible. The follow-ing formula has been used to describe the height dependency

⎟⎟⎠

⎞⎜⎜⎝

⎛

⎟⎟⎠

⎞⎜⎜⎝

⎛

⋅=

0

0

ln

ln

zHzH

vvref

refh

Equation 5-3 vh: Wind speed evaluation height ( vref: Wind speed reference height H: Reference height z0: Roughness length

In a study formerly performed by the EC-ASEAN Energy Facility in 2007 [ECA07] altogether four sites have been chosen exemplary and assessed as suitable. On these four sites particular measurements of wind speed (in a height of 60m) and its time-dependency have been monitored over a period of one year. The sites are located mostly in the south of Vietnam and one on an island in the Chinese Sea, approximately 30km from the mainland. In Vietnam a wide variety of wind conditions can be found. To achieve presentable results we categorized the available sites into groups: poor wind, fair wind and good wind. From each group one site was selected exempla-rily in representation of the whole group. We chose the sites “Phuoc Minh” (south, approximately 15km from the coastline), “Tuy Phong” (south, approximately 3km from the coastline) from the EC-ASEAN study. In order to make any representative conclu-sions, sites from other regions have to be taken into consideration as well. With reference to another report [internal sources] dealing with wind power in Vietnam a suitable site named “Sam Son” (north, located on an peninsula 500m from the coast) has been chosen (Wind data for this site was available from the same source).

• Poor: Mean annual wind speed 5,8 m/s, “Sam Son” • Fair: Mean annual wind speed 6,7 m/s, “Tuy Phong” • Good: Mean annual wind speed 7,22 m/s, “Phuoc Minh”)

The World Bank has also assessed South-East Asian Wind resources in its Wind Atlas published in 2001. Values for the mean annual wind speed at different sites in this study generally were about 10-12% higher than in the EC-ASEAN study. Hence we relied on the (measurement based) values from the EC-ASEAN study and not on the simulation based (and far too optimistic) World Bank Wind Atlas. The wind categorization in the World Bank study was also performed differently as it can be seen in Table 1-1.

4890S11/FICHT-5530494-v1 5-3

Average wind speed

Low < 6 m/s

Medium 6-7 m/s

Relatively high

7-8 m/s

High 8-9 m/s

Very high > 9 m/s

Table 5-1: Wind categories [World Bank Wind Atlas SE Asia]

Figure 5-1: Location of the chosen sites [internal sources]

These sites feature the following wind speed distribution.

Figure 5-2: Wind Speed distribution in a height of 65 m (Rayleigh) at the chosen sites

Wind speed distribution

0,00

0,02

0,04

0,06

0,08

0,10

0,12

0,14

0 5 10 15 20 25 30

Wind speed [m/s]

prob

abili

ty

Poor WindCondit ions

Fair Wind Condit ions

Good Wind Condit ions

4890S11/FICHT-5530494-v1 5-4

5.2 Selection of reference wind turbines

In this study several wind turbines from different size-categories and manufacturers have been chosen as reference. The main reason is that each site demands different plant characteristics. The wind turbines are classified into three major size-categories.

Small Medium Large <1 MW 1 – 2 MW 2 – 3 MW S1 Suzlon S52 (0,6MW) M1 Nordex S70 (1,5MW) L1 Enercon E-70 (2,3MW) S2 Enercon E-33 (0,3MW) M2 GE 1.5s (1,5MW) L2 Nordex N90 (2,3MW) S3 Ecotècnia 48 (0,8 MW) M3 Vestas V80 (2,0MW) L3 GE 2.5xl (2,5MW) S4 Vestas V52 (0,9MW) M4 Gamesa G80 (2,0MW) L4 Nordex N100 (2,5MW) M5 REPower MD77 (1,5MW) L5 Vestas V90 (3,0MW) L6 REPower 5M (5MW)

Table 5-2: Reference wind turbines All relevant technical data (power rating, cut-in wind speed, cut-out wind speed, power curve, available hub heights, rotor diameter) has been gathered from the manufacturers.

5.3 Annual gross electricity production

With the technical description of the wind turbine (power curve) and the site specific wind data it is possible to calculate the annual electricity generation of the wind turbine using the following formula

∑ Φ⋅=a

e

v

vvPE )(

Equation 5-4

ve: Cut-in wind speed (m/s) va: cut-out wind speed (m/s) P(v): Power in dependency of wind speed (kW) Φ: Frequency distribution of wind speed at the site (in h)

5.4 Capacity factor

The capacity factor is evaluated by dividing the actual electricity generation (see Equation 5-4) with the maximum annual possible electricity generation of the plant.

ratedPhEc⋅

=8760

Equation 5-5

E: Annual electricity generation Prated: Power rating of the wind turbine

4890S11/FICHT-5530494-v1 5-5

Depending on the site quality we have evaluated capacity factors in the range of 0,17 – 0,40. Poor sites are arranged between 0,17 and 0,29, fair sites have a capacity factor of 0,25 – 0,38 and good spots 0,27 – 0,42.

0,15

0,20

0,25

0,30

0,35

0,40

0,45

S1 S2 S3 S4 M1 M2 M3 M4 L1 L2 L3 L4 L5 L6 M5

c

Figure 5-3: Capacity Factor at site „Sam Son“ (poor wind)

0,15

0,20

0,25

0,30

0,35

0,40

0,45

S1 S2 S3 S4 M1 M2 M3 M4 L1 L2 L3 L4 L5 L6 M5

c

Figure 5-4: Capacity Factor at the site “Tuy Phong” (fair wind)

0,15

0,20

0,25

0,30

0,35

0,40

0,45

S1 S2 S3 S4 M1 M2 M3 M4 L1 L2 L3 L4 L5 L6 M5

c

Figure 5-5: Capacity Factor at the Site “Phouc Minh” (good wind)

4890S11/FICHT-5530494-v1 5-6

In order to demonstrate the strong dependence of electricity generation of a plant on the hub height, the capacity factor of a Vestas V52 wind turbine for different available tower heights is disputed. An increase of the capacity factor from 0,29 to 0,34 means a plus of 380 full-load hours.

0,00

0,05

0,10

0,15

0,20

0,25

0,30

0,35

0,40

45 m 50 m 55 m 60 m 65 m 70 m 75 m 80 m

Hub height

c

Good Wind Conditions

Fair w ind conditions

Poor Wind Conditions

Figure 5-6: Height dependence of capacity factor Vestas V52

5.5 Equivalent full load hours

The equivalent full load hours are calculating by multiplying the capacity factor c with the total number of hours in one year (8760).

5.6 Investment costs

The investment costs for wind power can be split into wind turbine costs9 and incidentals (Foundation, construction, grid connection, legal & financial costs, electrical infrastructure and miscellaneous). It is assumed that the wind turbine pricing takes place on a global market and therefore data from Europe and North America can be applied one-to-one on Vietnam. The specific costs for the incidentals not yet have been clarified with our Viet-namese partners and therefore have been assumed as European standard.

5.6.1 Wind turbine

The database on the costs of wind turbines is limited, as manufacturers do not provide prices in many cases. Hence this study falls back on information from own Fichtner-projects, the European Wind Energy Association [EWEA09], the World Bank [ESM08], the International Energy agency [IEA08] technical literature [Hau08], the German Ministry of the Environ-ment [EEG07] and own estimates, that are applicable for further differentia-tion as the sources offer data mostly highly generalized. Altogether data

9 Including transportation to site, erection and commissioning

4890S11/FICHT-5530494-v1 5-7

about 27 wind turbines has been evaluated. None of the information is older than 2008 because referring to “2008 Wind Technologies Market Report” [LBL09] wind turbine prices have experienced a significant increase (100%) from 2000 until 2007 to show signs of easing again in 2008. As input-values for the calculation of the levelized electricity costs the average values from Figure 5-7 have been used. Figure 5-7: Averaged investment costs wind turbine Wind turbines in the three size-categories are available with different hub heights. As electricity generating costs of a wind turbine depend predomi-nantly on the hub height a further relation to the investment costs has been worked out. Table 5-3 shows the typical hub height range and its average. In the following the term hub height will be used synonymous with tower height. Hub Height Small Medium Large Range 35 – 75 m 60 – 115 m 70 – 120 m

Average 55 m 87,5 m 95 m Table 5-3: Typical Hub Heights We used the average values for the hub height from the table above as standard tower heights of each size-category, which therefore are included in the investment costs (refer to Figure 5-7). Every variation of the standard tower height results in a change of the individual investment costs. The National Renewable Energy Laboratory in late 2006 published a report on a “Wind turbine design cost and scaling model” [NREL06]. This study provides a viable approach for estimating the costs of the tower by setting the mass of the tower and the steel price as the most relevant factors influ-encing the tower price. The tower price can be evaluated by using the following formula:

Tower cost = (0,3973 · Swept Area · Hub Height - 1414) · Steel Price

NREL has used the steel price of July 2002 in its study. Please not that the steel price has decreased since Sept 2008 rapidly and now equals to ap-

Small Medium Large0

200

400

600

800

1.000

1.200

1.400

1.600

1.800

2.000$/

kW

4890S11/FICHT-5530494-v1 5-8

proximately 0,6 USD/kg10, this is the value used by Fichtner. In the next step the price of the standard tower is subtracted from the investment cost of the wind turbine and the price of the actual tower added afterwards.

Actual wind turbine cost = wind turbine – standard tower + actual tower Figure 5-8: Relation hub height to investment cost Figure 5-8 shows exemplarily the investment costs of a Vestas V52 wind turbine (0.9 MW, 52 m rotor diameter) for the available hub heights. The change from the 45 m tower to the 75 m tower comes along with a cost increase of 1.5%, this number is so humble because of the rather low steel price (in July 2008 with a steel price of 1.30 USD/kg cost increase would have been 3.2%). Considering the total CAPEX including incidentals, the influence of the hub height even reduces to a modest 1.2%.This procedure has been applied to all the reference wind turbines in the LEC calculation. It is assumed that wind turbine pricing takes place on a uniform interna-tional market. Therefore no information about local prices has been gathered on this issue.

5.6.2 Incidentals

In technical literature common values for the incidentals are in the range of 28 – 40 % of the wind turbine’s investment costs [EWEA09 and HAU08]. The precise value primarily depends on the application case (wind farm size/single-turbine, country of commissioning) and the voltage-level the plant is connected to [HAU08]. The values mentioned above are applicable for plants being erected in Europe. It is assumed that incidental costs depend partly on local cost structures in Vietnam. We assume that foundation works, construction works, grid connection services and internal electrical infrastructure will be done by local firms thus local prices will apply. The values for financing & legal costs and miscella-

10 Refer to http://www.steelonthenet.com/prices.html for steel prices (accessed July 30th

2009)

Vestas V52

1.1771.183

1.190

1.203

1.216

1.150

1.160

1.170

1.180

1.190

1.200

1.210

1.220

45 m 50 m 55 m 65 m 75 m

Hub height

US$

/kW

4890S11/FICHT-5530494-v1 5-9

neous have been adopted from European projects. The cluster “Miscellane-ous” comprises the components: ecological compensation schemes (1.5 %), remote management system (0.5 %), costs for consents, other expertises and construction pre-planning incl. legal permit (4 %), execution & surveillance of construction works (7 %), loan and interim financing during construction period (3 %).

5.6.2.1 Local cost structure

We determined the local costs by asking for offers for these services from local companies. For this purpose, we assumed a project scenario consisting of 20 wind turbines with a capacity of 1.5MW and a hub height of 85m each resulting in a wind farm capacity 30 MW. A similar project situated in the Tuy Phong district of Binh Thuan has been commissioned in the first quarter of 2009. Fichtner calculated all incidentals as a percentage of the ex works-price of 20 Nordex S70 turbines (USD 2,172,344 per turbine). These evaluated percentages for the Nordex S70 wind turbine has been transferred on and equally used for the LEC calculation of the other turbines listed in section 5.2. Foundation The foundation of a wind power plant represents a significant share of the total project costs. The foundation is constructed differently depending on the ground structure and wind situation. Two different construction methods for two different ground structures are distinguished: Soft grounds that make the use of foundation piles mandatory and grounds with a relatively good load capacity only demanding a simple raft footing. For Vietnamese soils pile footing is necessary and thus applicable. The Vietnamese average price for the foundation has been determined to be USD 102,756 which equals to 4.7 % of the ex-works price of the turbines. Construction

Construction comprises everything related to site development e.g. road works, fences, gates. The base area of the foundation will be 240 m² per wind turbine. Under assumption of a quadratic shaped area, approximately 62 m of fencing is needed per turbine (total 1,240m). Per wind turbine one lockable gate is to be installed, enabling the access of the base area over the foundation with a personal car or light truck. If not already existent anyway suitable simple single-lane roads capable of carrying the tonnage of the vehicles used for erection and transportation (50–70 t11) have to be built from the nearest established road to each wind turbine. For our estimation we assume that 5 km roads to the wind farm have to be built. The average local prices determined by IoE are: Fencing per km: USD 29,314; gates per piece: USD 648; road works per km: USD 77,105.

11 See http://www.rwe.com/web/cms/de/46242/rwe-magazin/energien-aus-wasser-wind-biomasse/so-entsteht-ein-windkraftwerk/

4890S11/FICHT-5530494-v1 5-10

For the complete wind farm an amount USD 434,842 will have to be spent on Construction works in Vietnam. This equals to 1.0 % of the ex-works price of the turbines. Grid connection The above specified scenario wind project is to be connected to the 20kV voltage grid12. For the actual site location the length of the connection is estimated with 6km. EVN stated that their grid is currently capable of any capacity addition at any location within the country, thus the operator only has to pay the grid connection to the nearest grid-connection point (shallow charging). The erection of a transfer station is also part of this subject. The infrastructure should be able to handle the full (peak) power output of the wind farm. One kilometre of MV transmission line costs in average USD13,797 in Vietnam; the transfer station capable of handling 30 MW is priced in average with USD70,539. For the complete wind farm an amount USD 153,325 will have to be spent on grid connection in Vietnam. This equals to 0.35 % of the ex-works price of the turbines. Electrical infrastructure (internal)

This comprises all infrastructure on the area of the wind farm. In particular 8.5 km [Hau08] of 20kV AC (underground) cabling and 20 kV switchgear. The infrastructure should be able to handle the full (peak) power output of the wind farm. One kilometer of underground cabling costs in average USD 22,873.29. With information from European projects a share of 1.0% of the ex-works price of the turbines is estimated for internal electrical infrastructure. In summary the investment incidentals for wind projects realized in Viet-nam are estimated with 25.1 % of the ex-works price of the wind turbine (). Compared with Europe this figure is about 22 % lower.

12 Transformers are included in standard scope of supply from wind turbine manufacturers

4890S11/FICHT-5530494-v1 5-11

1.0%

4.7%

0.35%

1.00%

2.00%16.00%

Construction Foundation Grid-connection Electrical Infrastructure Financing, legal costs Miscellaneous

Figure 5-9: Costs of incidentals as a percentage of wind turbine costs.

5.7 Operation & maintenance costs

O&M costs can be split into fixed and variable costs [KON08]. The variable costs are land rent13 and variable maintenance costs. The fixed costs accrue also if the plant produces no electricity and are expressed in % of the investment of the mere wind turbine. Information on the amount of the O&M costs is taken from operational experience of existing plants, [KON08], [HAU08]. It is assumed that some components of the O&M have different costs in Vietnam. This applies mainly to labour costs and land rent. For the other components (e.g. spare parts and the service contract) the European level of costs has been used.

5.7.1 Local cost structure

Determination of the relevant local costs has been performed by IoE on the basis of a questionnaire elaborated by Fichtner. IoE has demanded pricing offers from local companies and submitted them to Fichtner. Labour costs Every wind turbine has a regular service effort (maintenance agreement) of 0.25 person/year. The labour costs are usually not included in the service agreement and billed separately. The necessary level of qualification is a well-educated technician or mechanic as in routine maintenance only “simple” tasks (oil change in the gearbox and hydraulic system, visual inspection of the rotor blades, check and retorquing of the most important flange connections etc.) are performed. The annual average costs of a service technician - with an educational level like described above - arising to the servicing company in Vietnam are 6,000 USD. 13 The land loan depends on the plants annual electricity generation

4890S11/FICHT-5530494-v1 5-12

Land rent

In most cases wind power projects are not realized on proprietary land, but on rented land. Renting offers the operating utility fiscal benefits. The rent consists of the leasehold fee for the actual base area the wind turbine is physically erected on and the operator’s duty to pay compensation for neighbouring land (distance space) being affected in some form by the installation. It is a usual approach to split the leasehold fee into a basic (fixed) part and a variable part. The fixed part is paid even when the wind turbine does not generate electricity e.g. due to unscheduled downtime. The basic remuneration amounts usually to between USD 10,500 and 14,000 in Germany. Due to a low number of implemented wind projects in Vietnam and missing experience in plant operation no credible data could be gathered on the issue of land rent. Our approach therefore uses an estimation of 0.003 USD/kWh which is slightly (about 38%) lower than in comparable European projects. Fehler! Verweisquelle konnte nicht gefunden werden. provides an overview about the approaches regarding the annually arising O&M costs made by Fichtner.

Table 5-4: Operation and Maintenance costs of a Nordex S70 installation. *) Escalation rate 3% per annum Discount factor 1+WACC

5.7.2 Escalation of O&M costs during technical lifetime

O&M expenses are not equal over the complete lifetime of a wind turbine. [LBL09] and [EWEA09]. Whereas in the first two years the O&M costs are relatively low (because of the manufacturer’s warranty) they increase

Technical Input DataRotor diameterHub Height 65 m 85 m 100 m 110 mCapacitiy of Turbine MWMaintenance

Maintenance agreement, fix % Invest / yr 0.50% 0.50% 0.50% 0.50%Maintenance, variable $/kWh 0.0049 0.0049 0.0049 0.0049Repair and Maintenance effort % Invest / yr 1.3% 1.3% 1.3% 1.3%

Insurances % Invest / yr 0.7% 0.7% 0.7% 0.7%Reserves disposal % Invest / yr 0.8% 0.8% 0.8% 0.8%Personell requirement (0.25 pers. / WTG) Pers. / yr 5.00 5.00 5.00 5.00Personell expenditures $ / Pers. / yr 6,000 6,000 6,000 6,000Land rent $ / kWh 0.0030 0.0030 0.0030 0.0030OPEXO&M (Fixed cost) $ / yr 1,463,747 1,473,838 1,481,407 1,486,453

Maintenance agreement, fix $ / yr 217,234 218,763 219,910 220,675Repair and Maintenance effort $ / yr 564,809 568,785 571,766 573,754Insurances $ / yr 304,128 306,269 307,874 308,944Reserves disposal $ / yr 347,575 350,021 351,856 353,079Personell expenditures $ / yr 30,000 30,000 30,000 30,000

O&M (Variable costs) Variable O&M poor wind $ / yr 417,448 457,236 481,476 495,713 Variable O&M fair wind $ / yr 596,886 642,753 670,159 686,075 Variable O&M good wind $ / yr 676,761 723,952 751,927 768,097Levelized OPEX poor wind *) $ / yr 2,351,288 2,413,632 2,453,389 2,477,490Levelized OPEX fair wind *) $ / yr 2,575,566 2,645,507 2,689,222 2,715,422Levelized OPEX good wind *) $ / yr 2,675,401 2,746,997 2,791,423 2,817,940

1.5 MW

70 m

Nordex S70

4890S11/FICHT-5530494-v1 5-13

continuously with time in operation due to increasing repair effort. In our approach an escalation rate of 3 % p.a. is to be applied (1 % p.a. real escalation plus 2 % inflation in the dollar zone)

5.7.3 Weighted average cost of capital

For the calculation of the Weighted Average Cost of Capital (WACC) we assume a typical debt share of has been calculated with the assumption that the asset comes with 70 % from debt capital and 30 % from equity. With return on equity of 15 % and a debt interest rate of 10 % this leads to a nominal WACC of 11.50 %.

Equity DebtAsset 30.0% 70.0%return / interest rate incl. taxes 15.0% 10.0%WACC nominal 11.50%

Table 5-5: Weighed Average Cost of Capital.

5.7.4 Levelised O&M costs

The levelized OPEX are calculated by using a formula transforming a series of regular escalating payments into a constant annuity.

( )( )

( )( )1

1−−

⋅−−

⋅= n

nn

qq

pqpqkLO

Equation 5-6 p: rate of escalation, here: 3 % p.a. q: Weighted Average Cost of Capital n: technical lifetime, here: 20 years k: payment in the year 0

5.8 Wind farm net electricity generation

The amount of electricity calculated in section 5.3 is gross electricity generation of a single turbine. From this value the auxiliary power demand of each turbine (due to remote management, active pitch-/stall-system and active yaw control et cetera) and the park efficiency (due to “shadowing” effects) has to be subtracted. We assume a park efficiency of 96 % and the auxiliary power demand with 0.15% of the turbines’ gross electricity generation.

5.9 Levelised electricity generation costs

With the wind data from each site and the technical information about each wind turbine it is possible to calculate the annual electricity production and the equivalent full load hours (EFLOH) for every case examined (altogether

4890S11/FICHT-5530494-v1 5-14

123 cases14). Together with the information on CAPEX15 (transformed into a constant annuity with the nominal WACC) and OPEX it is possible to determine the Levelised Electricity Generation Costs (LEC). The LEC basically evaluates by dividing the levelised required revenue (LRR) with the total annual net electricity generation of the wind farm.

LRR = A + MI LRR: levelised required revenue A: constant annuity on CAPEX MI: levelised O&M costs

The next table shows the full calculation for the scenario wind project consisting of 20 Nordex S70 wind turbines. The calculation has been performed for all available hub height of this model.

14 15 different wind turbines, about 3 different hub heights per turbine, 3 sites, 15 Wind turbine and incidentals

4890S11/FICHT-5530494-v1 5-15

Technical Input DataRotor diameterHub Height 65 m 85 m 100 m 110 mCapacitiy of Turbine MWNumber of wind turbines Number 20 20 20 20Capacity of Wind farm MW 30 30 30 30Efficiency % 96% 96% 96% 96%Energy generation, gross, poor wind MWh 52,842 MWh 57,878 MWh 60,946 MWh 62,749 MWhEnergy generation, gross, fair wind MWh 75,555 MWh 81,361 MWh 84,830 MWh 86,845 MWhEnergy generation, gross, good wind MWh 85,666 MWh 91,639 MWh 95,181 MWh 97,227 MWhAuxiliary power % 0.15% 0.15% 0.15% 0.15%Energy generation, net, poor wind MWh 52,762 MWh 57,791 MWh 60,855 MWh 62,654 MWhEnergy generation, net, fair wind MWh 75,442 MWh 81,239 MWh 84,703 MWh 86,715 MWhEnergy generation, net, good wind MWh 85,538 MWh 91,502 MWh 95,038 MWh 97,082 MWhFull Load Operating Hours, poor wind h / yr 1,761 1,929 2,032 2,092Full Load Operating Hours, fair wind h / yr 2,519 2,712 2,828 2,895Full Load Operating Hours, good wind h / yr 2,856 3,055 3,173 3,241Economic Input DataWeighted Average Cost of Capital % 11.50% 11.50% 11.50% 11.50%Lifetime yr 20 20 20 20WTG Price input $ / kW 1,460 1,460 1,460 1,460 Price standard tower $ / kW 44 44 44 44 Price specific tower $ / kW 33 43 50 56 WTG incl. common services $ / kW 1,448 1,458 1,466 1,471Incidentals Construction % 1.0% 1.0% 1.0% 1.0% Foundation % 4.7% 4.7% 4.7% 4.7% Grid-connection % 0.35% 0.35% 0.35% 0.35% Electrical Infrastructure % 1.0% 1.0% 1.0% 1.0% Financing, legal costs % 2.0% 2.0% 2.0% 2.0% Miscellaneous % 16.0% 16.0% 16.0% 16.0%Maintenance

Maintenance agreement, fix % Invest / yr 0.50% 0.50% 0.50% 0.50%Maintenance, variable $/kWh 1.4 0.0049 0.0049 0.0049 0.0049Repair and Maintenance effort % Invest / yr 1.3% 1.3% 1.3% 1.3%

Insurances % Invest / yr 0.7% 0.7% 0.7% 0.7%Reserves disposal % Invest / yr 0.8% 0.8% 0.8% 0.8%Personell requirement (0.25 pers. / WTG) Pers. / yr 5.00 5.00 5.00 5.00Personell expenditures $ / Pers. / yr 1.4 6,000 6,000 6,000 6,000Land rent $ / kWh 1.4 0.0030 0.0030 0.0030 0.0030CAPEXSpecific CAPEX $ / kW 1,813 1,826 1,835 1,842Total CAPEX $ 54,384,201 54,766,980 55,054,065 55,245,455OPEXO&M (Fixed cost) $ / yr 1,463,747 1,473,838 1,481,407 1,486,453O&M (Variable costs) Variable O&M poor wind $ / yr 417,448 457,236 481,476 495,713 Variable O&M fair wind $ / yr 596,886 642,753 670,159 686,075 Variable O&M good wind $ / yr 676,761 723,952 751,927 768,097Levelized OPEX poor wind *) $ / yr 2,351,288 2,413,632 2,453,389 2,477,490Levelized OPEX fair wind *) $ / yr 2,575,566 2,645,507 2,689,222 2,715,422Levelized OPEX good wind *) $ / yr 2,675,401 2,746,997 2,791,423 2,817,940Levelized annual costsLevelized annual CAPEX $ / yr 7,053,891 7,103,539 7,140,776 7,165,600Levelized annual total costs poor wind $ / yr 9,405,179 9,517,171 9,594,164 9,643,090Levelized annual total costs fair wind $ / yr 9,629,457 9,749,047 9,829,997 9,881,022Levelized annual total costs good wind $ / yr 9,729,292 9,850,537 9,932,198 9,983,540Levelized electricity cost

Poor wind $ / kWh 0.178 0.165 0.158 0.154Fair wind $ / kWh 0.128 0.120 0.116 0.114Good wind $ / kWh 0.114 0.108 0.105 0.103Average $ / kWh 0.140 0.131 0.126 0.124

1.5 MW

70 m

Nordex S70

Table 5-6: LEC calculation for scenario wind project consistent of 20 Nordex S70 The LEC spread widely in our calculation due to its dependency on the turbine type, hub height, and site conditions (Table 5-7). For poor wind sites the range is between 0.122 and 0.213 USD/kWh, fair wind sites are located between 0,091 and 0.150 USD/kWh, good sites are situated in the cost region of 0.083 up to 0.132 USD/kWh.

Average Minima Maxima

Poor wind 0.159 $/kWh 0.122 $/kWh 0.213 $/kWhFair wind 0.117 $/kWh 0.091 $/kWh 0.150 $/kWhGood wind 0.105 $/kWh 0.083 $/kWh 0.132 $/kWh Table 5-7: Range of levelised electricity generating costs in the examined sample of wind turbines.

4890S11/FICHT-5530494-v1 5-16

In order to make a conclusion about the frequency that specific LEC emerge, the total amount of results has been classified in bands of 1 USct width. Figure 5-10 shows the cumulative frequency distribution of the LEC over all sites differentiated between site quality.

Figure 5-10: Cumulative Frequency distribution of sample wind turbines LEC over all sites On “good” sites 56% of all reviewed combinations have LEC below 0.105USD/kWh, whereas on “fair” sites only 12% are below.

5.10 Wind energy potential in Vietnam

Vietnam is one of the countries with the richest wind resources in Southeast Asia. Some areas (mainly at the coast) are suited exceptionally well for wind power usage due to abundant wind resources and high proximity to population centers. Several studies have been performed concerning the technical potential of wind power in Vietnam. One of the most detailed is the Wind Atlas of South East Asia published by the World Bank. The findings are summarized in Table 5-8.

Average wind speed

Low < 6 m/s

Medium 6-7 m/s

Relatively high

7-8 m/s

High 8-9 m/s

Very high

> 9 m/s

Sum

Area (km2) 197,242 100,367 25,679 2,178 111 Area (%) 60.60% 30.80% 7.90% 0.70% >0% 100% Potential (MW) 401,444 102,716 8,748 452 512,864 Table 5-8: Wind Energy Potential in Vietnam [World Bank] Experience has shown that the potential assumed by the World Bank Wind Atlas are in general far too optimistic [Ngu06] as its data is based on meteorological simulations, not on measures, in a bulk part. Furthermore no restrictions on technical and/or economical feasibility have been imposed on the data.

0%

20%

40%

60%

80%

100%

0.05$/kWh

0.07$/kWh

0.09$/kWh

0.11$/kWh

0.13$/kWh

0.15$/kWh

0.17$/kWh

0.19$/kWh

0.21$/kWh

0.23$/kWh

Good

Fair

Poor

4890S11/FICHT-5530494-v1 5-17

A report prepared by Mr. Khan Nguyen modifies the Wold Bank’s findings by imposing feasibility restrictions on certain areas. For instance there are sociological restrictions that forbid wind power usage in areas that have a too high population density and economical and/or technical restrictions that limit the implementation of wind power in areas with mountainous shape for example. Taken all restrictions into account the report concludes a much lower feasible potential (which in fact still is remarkable) of 120.5 GW, but does not differentiate between wind classes. The two sources have been combined using the wind source classification and the appropriate percentage of area from the World Bank report and the total feasible potential from Nguyen’s study (Table 5-9).

"POOR" "FAIR" "GOOD" High Very high

Sum Wind Class Average wind speed < 6 m/s 6-7 m/s 7-8 m/s 8-9 m/s > 9 m/s Area (km2) 197.242 100.367 25.679 2.178 111 Area (%) 60.60% 30.80% 7.90% 0.70% >0% Potential (MW) 40,000 94,230 24,110 2,053 106 120,500Percentage of tot 78.2% 20.0% 1.7% 0.1%

Table 5-9: Modified Wind Energy Potential [World Bank and Nguyen] No information is available about the Wind Energy Potential at locations with “poor” wind resources. For the calculation a value of 40,000MW has been assumed. Multiplying the category specific wind energy potential (Table 5-9) with the cumulative frequency distribution of LEC (Figure 5-10) leads to Figure 5-11 and Figure 5-12 providing information about how much capacity can be added at a certain level of tariff. The same figure is given for all site catego-ries (Figure 5-12).

MW10,000 MW

20,000 MW30,000 MW

40,000 MW50,000 MW60,000 MW70,000 MW80,000 MW

90,000 MW100,000 MW

0.05$/kWh

0.07$/kWh

0.09$/kWh

0.11$/kWh

0.13$/kWh

0.15$/kWh

0.17$/kWh

0.19$/kWh

0.21$/kWh

0.23$/kWh

GoodFairPoor

Figure 5-11: Potential new capacity in dependence of tariff-level

4890S11/FICHT-5530494-v1 5-18

MW

50,000 MW

100,000 MW

150,000 MW

200,000 MW

0.05 $/kWh 0.09 $/kWh 0.13 $/kWh 0.17 $/kWh 0.21 $/kWh

Figure 5-12: Potential new capacity in dependence of tariff-level We recommend setting the initial tariff at 0.105 USD/kWh for the year 2010. This tariff would allow for developing an average site which features good wind conditions. Our analysis shows that a capacity of 25 GW could be mobilized at these costs not considering site restrictions beyond pure wind conditions. So we assume that this tariff would be sufficient to meet the target of 629 MW by 2020.

5.11 Sensitivity analysis

In the following a sensitivity analysis has been conducted on the level of LEC. The cost-components having the hugest impact on the level of LEC and being likely to change in the future have been varied in the range of +/- 60 % of the base value from the actual calculation. The effects of variation of two items (+/-) are pointed out exemplary in written form below. The term Plus-/Minus-Scenario refers to the direction of development of the LEC in case of a variation of single cost-components. Wind turbine ex-works prices Plus-Scenario: Due to a rapid price increase of raw materials needed for

wind turbine production (copper, steel..) the prices of wind turbines also could increase.

Minus-Scenario: Due to technological learning or new construction materi-

als the prices could drop drastically Interest rates Plus-Scenario: If the political/fiscal framework in a country is not reli-

able, risk for investors is high and therefore capital costs rise. Also a different form of financing (e.g. public funds or loans from a development bank at a preferential interest rate) could lower capital costs.

4890S11/FICHT-5530494-v1 5-19

Minus-Scenario: If the government installs a political framework providing investors a good climate of investment, risks will be as-sessed less severe, making it easier to get a loan at a lower interest rate. Realizing projects with a lower rate of equity will also increase capital costs.

0.080 $/kWh

0.090 $/kWh

0.100 $/kWh

0.110 $/kWh

0.120 $/kWh

0.130 $/kWh

40% 60% 80% 100% 120% 140% 160%

personnel costs

equity return rateland rent

foundation works

WTG price

grid connection&electrical infrastructure

debt capital interest rate

Figure 5-13: Sensitivity analysis of selective aspects

4890S11/FICHT-5530494-v1 6-1

6. Guaranteed Payment Period Investment costs dominate the lifecycle costs of wind power plants. This means that once a plant is built the opportunities to decrease costs are rather limited. Thus, reasons for renegotiating the level of remunerations are very limited. Fixing the tariffs for a longer term is therefore reasonable. At the same time long-term fixed tariffs provide certainty to the investors allowing access to low cost long term debt. This has been a very important precondi-tion for the success of feed in tariffs in many countries. Terms between ten and twenty years can be found in different European regulations Table 6-2. For wind power, a split tariff has been established in France and Germany, allowing higher remuneration in early years of a plant’s life time than in the later years. In Portugal, during the fixed duration of support, wind energy producer receive a monthly payment that is calculated by a special formula, including inflation adjustment. Experience has shown that tariffs should be guaranteed for a reasonably long period of time, not less than 15 years. Shorter periods of time could hamper investment security. Regarding the life-time of wind power plants twenty years is a reasonable term. The standard power purchase agreement for small hydro power plants (Decision No. 18/2008/QD-BCT MoIT) stipulates also a term of twenty years. We thus recommend a term of twenty years. The shorter the period the preferential Feed in tariff is guaranteed, the higher is the level of remuneration to be guaranteed to recover the costs. A sensitivity analysis based on the tariff in regard to the payment period resulted in the following changes: Payment Period Required tariff Change of tariff com-

pared to 20 year payment duration

10 Years 0.132 + 26% 15 Years 0.113 + 8% Table 6-1: Change of tariff compared to 20 year payment duration Decree 78/2007 and payment term The Decree 78 encourages domestic and foreign investors to invest in, and arrange financing for, infrastructure facilities like power plant projects. A BOT project is a partnership between the government and a foreign investor based on a contract to implement an infrastructure project that would normally be carried out by a government agency. A BOT contract is signed between competent state authorities with inves-tor(s) to build and operate infrastructure within a period of time. When that period expires, investor(s) shall transfer the infrastructure facility, without compensation, to the state. Projects in the form of a BOT contract obtain investment incentives and guaranties like import duty exemptions.

4890S11/FICHT-5530494-v1 6-2

If wind power projects get implemented as BOT projects the transfer shall take place after the payment term of the feed in tariff. After this time the investment capital of the investor has been recovered. However, after this time wind turbines are normally at the end of their lifetime and have to be replaced by new and more efficient wind turbines.

Country Duration of support [years]

Austria 10 California 5-20 Cyprus 15 Czech Republic 20 Estonia 12 France 15 - 20 Germany 20 Great Britain (proposed) 20 Greece 12 Ireland 15 Italy 15 Latvia 10 Lithuania 10 Luxembourg 10 Philippines At least 12 Portugal 15 Slovakia 12 Slovenia 15 South Africa 20 Spain 20 Sri Lanka Depend on option either 20 or 9-15 Switzerland 20 Ukraine 21 Table 6-2: Duration of support for wind energy in different countries. (Source: German

Federal Ministry for the Environment, Nature Conservation and Nuclear Safety (BMU): http://www.res-legal.eu/

4890S11/FICHT-5530494-v1 7-1

7. Tariff Adjustment Mechanisms for adjusting feed in tariffs are very important in an effective feed in tariff. Tariff adjustments or revisions help to anticipate changes of economic or technology conditions. However, investors need stable and reliable framework conditions. Frequent and unexpected tariff changes could cause investment security diminishing. Therefore, tariff adjustment mechanisms have to be carefully elaborated and scheduled in advance. Some changes of framework conditions like inflation or cost reductions through learning and economies of scale are foreseeable and should be anticipated by rules in the tariff allowing an automatic adaption to these changes. Other changes cannot be anticipated in advance. A review of the tariff following a fixed schedule say every four years should allow identify-ing the changing framework conditions and adapting the tariff accordingly. Moreover, any adjustment should only apply for newly commissioned power plants whereas tariffs should be not altered for existing wind power plants. The bulk of life cycle costs of wind power generation stems from the initial investment leaving only little room for further costs adjustments during the power plant’s life-time. Thus changing framework conditions have only little impact on generating costs of existing wind power plants and wind power plant operators have only little leeway to alter the generat-ing costs. Regarding wind power plant plants within the remuneration system, adjust-ments for inflation have to be considered. The tariff will apply for many years and therefore, inflation could impact the tariff, especially in countries with moderate to high inflation rates. If inflation adjustments were not implemented, after some years, the tariff would face the risk of being too low for a financial viable operation of wind power plants. To counteract such effect, the feed in law could provide that the tariff will be adjusted to Vietnam’s annual inflation rate. However, not all costs are subject to inflation. Capital costs are independent from inflation as long as the interest is fixed over the life-time of the plant. Lenders usually anticipate the inflation by asking for higher interest rates than with a situation without inflation. This has to be considered when calculating the level of tariffs based the levelised electricity generating costs. The operating expenses are in the range of 30% of total electricity generation costs of wind power plants. We recommend including a tariff adaption rule for inflation as follows

4890S11/FICHT-5530494-v1 7-2

aa

ii T

II

T ⋅⋅+= )3.07.0(

with 0.7: Share of tariff not effected by inflation 0.3: Share of tariff effected by inflation Ti : Feed in tariff in year i of operation of an individual plant Ii : Vietnamese consumer price index in year i of operation of an individ-

ual plant Ia : Vietnamese consumer price index in year a start of operation of an

individual plant Ta : Feed in tariff in year a start of operation of an individual plant This means that the start tariff for wind power plants will be adjusted for these individual wind power plants over the life time of the plants. Whereas inflation impacts the generating costs of existing wind power plants, learning effects and economies of scale will have an impact on new plants to be installed. It has been observed with different technologies including wind power that with growing deployment of a technology the costs are decreasing due to learning effects. That is why costs of electricity from wind power plants have substantially decreased globally since wind power plants were introduced in the early eighties. One goal of energy policy is to provide incentives for technology improve-ments and more efficient solutions in order to reduce the electricity genera-tion costs of wind power technology. The largest share of these costs is made up by the costs of power turbine itself and installation costs. The price for power turbines and the installation costs tend to decrease with market deployment due to technological learning. The decreasing costs should be reflected by the support policy. This can be done by reducing the tariff level for new installations during an annual revision and adjustment of tariffs or through a predefined degression. Tariff degression means that the tariff level depends on the year, when the wind energy project starts to operate. The level for new plants is reduced by a certain percentage each year. Neverthe-less, the tariff for plants already commissioned remains constant for the guaranteed duration of support. Consequently, the later projects get imple-mented the lower the reimbursement received. Thus incentives for technol-ogy improvements and cost reductions due to learning effects are provided. This approach minimizes the risk of overcompensation. A constant reduc-tion by a fixed factor shall be introduced. The following table shows an overview of the tariff adaption mechanisms for new installations applied by country.

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Country Tariff adaption mechanisms for new installations

Austria Regarding new plants, the amount of compensation is gradually reduced. The amount of price reduction is re-calculated every year

Czech Republic

The level of remuneration for new installations is set annually by the Energy Regulatory Office. These tariffs cannot decrease by more than 5% in relation to the year before

Estonia Statutory law does not provide for an adaptation mechanism France The decrees on the feed-in tariff for the single technologies (arrêtés) all

provide for annual adjustments to inflation of the tariffs for new systems. Tariff degression of 2% annually is applied for electricity from new wind turbines from the year 2008 on.

Germany The annual percentage degression for tariffs and bonuses for electricity generated from wind energy a) from offshore installations shall be 5.0 % from the year 2015 onwards, and b) from other installations shall be 1.0 %.

Italy Payments will be reduced by 2 or 4% for systems commissioned in 2009 or 2010. Systems commissioned later than 2010 will be subject to a new decree setting a new amount. If the new decree is not enacted, the amount set for 2010 shall apply.

Table 7-1: Tariff adaption mechanisms for new installations. Source: German Federal Ministry for the Environment, Nature Conservation and Nuclear Safety (BMU): http://www.res-legal.eu/ and Fraunhofer ISI, Energy Economics Group: Evaluation of different feed-in tariff design options

With global markets for wind power plants today learning mainly occurs on global markets i.e. the growth of installed wind power world-wide deter-mines mostly the cost reductions. Such learning will mainly occur with the wind power turbine and plant itself by a more rationale design and manufac-turing. The Vietnamese target of 500 MW by 2020 will only contribute marginally to the expansion of global wind power markets which had a volume of some 25,000 MW only installed last year (2008) and a total installed of 128,492 MW by July 2009. However, some of the learning occurs exclusively on the Vietnamese market. For instance the more wind power capacity will have been installed the larger is the experience of the local staff to commission such plants thus decreasing costs. To determine a reasonable annual degression factor for Vietnam, we need to split up the electricity generation costs of wind power plants in those components which are purchase and delivered via international markets and those components that are delivered in national markets. For the compo-nents purchased internationally we assume an annual cost degression of 1.5 % oriented on the cost reductions observed and the degression factors implemented in other countries. For components and services supplied domestically we assume a higher possible degression factor of 2 % since Vietnam is at the beginning of wind power deployment allowing a faster and more substantial learning than in later phases of deployment. However, learning effects will occur domestically only if at least the target of 500 MW by 2020 is met and will be more substantially if a higher and faster deploy-ment is achieved. We calculate a annual degression factor as follows

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=⋅+⋅=⋅−+⋅= %5.17.0%23.0)1( gv dxdxd 1.6% with d: annual degression rate of the tariff for new plants x: domestic cost share of components and services dv: assumed degression rate of domestic Vietnamese components and

services dg assumed degression rate of components and services purchased on

global markets So the initial tariff in the year of commissioning will be by 1.6 % lower for all wind power erected in a certain year than in the year before. Additionally to the scheduled fixed changes of tariffs, it is also recom-mended to review the tariff every four years, which includes the experience of the support scheme and allows suggesting tariff adjustments. Thus, changing unforeseeable circumstances can be taken into account. Other countries have implemented such an element in their regulation as well with good result. The German Renewable Energy Law provides to publish a report every four years while Spain will revise its tariffs, premiums, com-plementary payments and caps and floors as stated in the Royal Decree 661/2007 during the year 2010.

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8. Purchase Obligation Purchase obligations are obligations put on a certain entity in the electricity sector to buy electricity produced from renewable energy. Most European states have installed some kind of purchase obligation together with their feed in tariffs. If the feed in tariff is designed as premium to the market price no purchase obligation is stipulated as marketing occurs on the market. Against that a purchase obligation is a crucial element of a fixed feed in tariff since access the lack of opportunity to sell the wind power has been a mayor bottleneck to wind power deployment n the past. There are four questions to be answered when setting the purchase obliga-tion:

(1) Who should be obliged to buy the wind power? (2) How can the obliged party recover the additional costs from pur-

chasing the wind power?

(3) How can the obliged party pass on the purchased power to the final customer?

(4) What happens in case of transmission bottlenecks?

Ad (1) Who should be obliged to buy the wind power? This can be either

• power generators, • transportation-grid operators (TSO), • distribution-grid operators (DSO), • electricity suppliers, • electricity consumers, or • an independent (state) agency.

With the choice of the obliged party the following aspects have to be considered: (1) There should be exactly one obligated party for any RE plant. Other-

wise it might lead to confusion if several different entities are obligated with a certain power plant.

(2) The parties to be obligated should be able to market the renewable

electricity. At least they should be able to forward it to entities that are able to do so.

(3) The additional financial burden from the purchase of renewable power

should be distributed equally among all stakeholders since it is a na-tional target to deploy renewable energy.

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(4) The obligated purchase of power should not lead to a distortion of competition. This has to be considered only if the parties who finally bear the burden are in competition to each other.

(5) It must be feasible for power generators to enforce the obligation. (6) Grid should be reinforced to handle 95% of the installed wind power;

oblige the grid operators to install a feed in management system. (7) Force the grid operators to pay compensation to the plant operators in

case of Feed-In management caused income losses. The obligation to purchase the power from wind power plants is usually put on the particular grid operator to whose grid the wind power is fed. Ad (2) How can the obliged party recover the additional costs from purchasing the wind power?

There are several alternatives.

• Do not distribute the additional costs i.e. each obliged party will cover the costs itself.

• Share the additional costs equally among all obliged parties. • Allow cost recovery from final customers through higher grid

fees or electricity market prices. • The state covers the additional costs.

Ad (3) How can the obliged party pass on the purchased power to the final customer? The obliged party should be able to pass on the purchased power to the final customers to make best used of the generated electricity. Ad (4) What happens in case of transmission bottlenecks?

With higher penetration of wind power one may reach a situation that at certain times not all electricity generated can be absorbed by the grid. The feed in tariff or the power purchase agreement needs to stipulate whether plant operators shall be compensated for the lost and who should pay for the compensation. In the following sections the design models of purchase obligation of several countries using a feed in tariff will be out lined. In Germany the grid operators are obliged to purchase any electricity from renewable sources. Grid operators shall immediately and as a priority purchase, transmit and distribute the entire available quantity of electricity from renewable energy sources. The obligations above shall not apply where installation operators and grid operators agree by contract to deviate from this priority purchase in order to better integrate the installation into the grid [EEG08]. The additional costs resulting from the purchase obliga-

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tion are allocated equally among all transmission grid operators. They recover the costs through an additional tariff element in the grid fees. Notwithstanding their purchase obligation grid operators shall be entitled, by way of exception, to take technical control over installations connected to their grid (Feed-In management, amended to EEG in 2004) system with a capacity of over 100 kilowatts for the generation of electricity from renew-able energy sources, if the grid capacity in the respective grid area would otherwise be overloaded. The grid operator whose grid gives rise to the need for the assumption of technical control shall compensate those installation operators who were not able to feed in electricity to the extent agreed upon. The grid operator may, when determining the charges for use of the grid, add any charges arising due to compensation payments (Feed-In manage-ment) if the measure was necessary and he bears no responsibility for it. It depends on the actual level of compensation paid if - unless §12 EEG (hardship clause) is implemented - a financial disadvantage arises due to a Feed-In management caused cut-down of the power output of the plant. Until now most grid operators have installed a procedure allowing operators to call for compensation payment and have released the official calculation scheme for determining the lost remuneration16. Spain has been chosen as it has like Germany implemented a very effective feed in legislation having led to its role as one of the world’s top manufac-turers in wind turbines (e.g. Gamesa, Ecotècnia). The Spanish system contains the free choice of the producer concerning the remuneration. Wind power plant operators can choose, for periods of not less than one year, the option that suits them best:

(1) Fixed regulated tariff: Sale to the distributor at the regulated tariff, which is the same for all scheduling periods.

(2) Sale on the open market: Free market sale, through the bidding sys-tem managed by the market operator (OMEL).

Purchase obligation applies in case (1). In this case the electricity distributor has an obligation to buy electricity produced from RES (provided this is technically possible) at the price set in RD 436/2004 (Royal decree). Renewable electricity producers who expose themselves to short-term fluctuations in electricity requirements and prices by choosing option (2) and thereby incurring the risk of not being able to sell any electricity during low-demand periods, receive an additional incentive bonus. The National Commission of Energy (CNE) performs settlement of costs occurring by further integration of wind power and other renewable energies into the grid by compensating distributors who have paid the prices, premi-ums and incentives. The costs of electricity generation under this system are taken into account for the annual calculation of the tariff, together with other costs: costs of conventional electricity generation, permanent costs, compe- 16 See for example http://www.eon-netz.com/pages/ehn_de/EEG__KWK-G/Erneuerbare-_Energien-Gesetz/Downloads_Vorgaben_und_Formulare/Einspeisemanagement/index.htm accessed the 26th of August 2009

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tition transition costs, transport and distribution, commercial management, diversification and security of supply. In this way, the additional cost of the wind power deployment is covered by electricity consumers in a way that is proportional to their consumption. In the Spanish model, compensation depends on regulated electricity rates. Theoretically, this should reduce investment security. But since annually defined rates have not changed, decisively and suddenly, in the past years, and since such changes are not expected in the future, this arrangement – clearly enough – has not had any negative impact on the development of the Spanish market [Rag05]. The Spanish Model gives the operators relatively good security of Invest-ment. They can choose to be on the safe side (with purchase obligation and fixed guaranteed revenues) or to expose themselves to market competition (without purchase obligation and unsteady remuneration). This support scheme is applicable to all mature markets, with renewable electricity generation about to turn competitive without subsidies. The further devel-oped renewable energy technologies can opt for competition in the market while “fairly new technologies” rely on guaranteed remuneration. France has installed a capacity dependent support regulation for wind power and other electricity generating renewable energy technologies. Plants under 12 MW electrical capacity are guaranteed a feed in tariff for 15 or 20 years (onshore wind, hydro and PV). Large plants over 12 MW are supported within a tendering process [Zen09]. In France the law on the Modernisation and Development of the Public Electricity Service (Loi relative à la modernisation et au développement du service public de l’électricité (LRMDSP)) has implemented the relevant EU directive on the Promotion of Electricity Produced from RES into national legislation. In accordance with the LRMDSP the grid operator (mainly Electricité de France (EDF)) is required to purchase wind power at a preferential feed in tariff. EDF is owned by the French government and controls almost the entire market for electricity generation and distribution in the country. Gestionnaire du Reseau de Transport d'Electricite (RTE), a company nominally separate from, but controlled by EdF, operates the national high-voltage electricity grid. While EdF owns the network, RTE is legally independent of EdF, and French law requires that RTE allows equal and non-discriminatory access to the grid for all electricity distributors and generators.

Wind farms already erected or now in the approval process are only guaran-teed the purchase obligation if the capacity is lower than 12 MW. According to the new legislation (Nov. 2005) any wind turbine or –farm has to be within a “Development Zone for Wind Energy” (Zone de développement de l’éolien) in order to be qualified for the purchase obligation [Frö09-1]. Producers who wish to benefit from the purchase obligation must obtain a Certificate issued by the “Direction régionale de l’industrie de la recherche

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et de l’environnement” (DRIRE) that qualifies the generator and concludes a purchase contract with EDF.

The additional costs of feed in tariff and purchase obligation are passed on to electricity customers by a balance fund supervised by the state. This fund performs balance payments to the disadvantaged grid operators (mainly EDF). The payment to the grid operators occurs quarterly. The fund is financed by a usage-bound fee consumers pay on their electricity bill. This usage-bound fee is recalculated annually by a procedure documented in the law (Loi 200-108, Art. 6). The French situation before the deregulation demanded by the EU was quite similar (Albeit on another level of development) to the one in Vietnam: A large state-owned quasi monopolist with a large reliance on one form of energy controlled the market. Even today the market-dominance of EDF is very high in the generation sector and the national HV grid is still operated by one sole utility. In the light of the experiences gained in other countries and considering the particular situation in Vietnam we give recommendations for the purchase obligation in the following. The electricity market in Vietnam is currently not yet deregulated. The 2004 released Vietnam Electricity law forms the foundation for a transformation of the regulated electricity sector into a competitive electricity market. This deregulation will happen in stages: Phase 1 (2005-2014) foresees competitive generation with an increasing share of IPPs and a single buyer (EVN), Phase 2 (2015-2022) enables IPPs to also sell their (wholesale-) electricity directly to major end users. After 2022 the electricity sector will be opened fully also to retail- / household sales. By now almost the whole electricity sector is run by a quasi-monopolist, the Electricity of Vietnam (EVN). The EVN is a state-owned utility established in 1995. It is engaged in generation, transmission and distribution of elec-tricity in the whole country. Its market shares are 100% in the transmission-, 95% in the distribution- and 78% in the generation sector. Only the genera-tion sector has been mentionable opened to private market participants yet. Since 2001 IPPs have the possibility to make a PPA with EVN and feed electricity into EVN’s grid. EVN will focus on plants with more than 100MW capacity in the future and therefore give “small”-generation into private hands. Notwithstanding the electricity sector will not be fully deregulated: The state will maintain its monopoly over electricity transmis-sion, regulation of the national electricity system, and the construction and operation of large power plants considered significant for socioeconomic or national defence and security reasons [Fre05].

Acknowledging the international examples the transmission operator is the appropriate entity to impose the purchase obligation on. Vietnam has actually one sole transmission grid operator, the EVN. Choosing the EVN as responsible entity has – even though deregulation of the electricity market is in process – has some crucial advantages:

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• There is no other entity able to handle this task yet • EVN runs almost the complete transmission-/distribution infrastructure • => No doubt about responsibilities • EVN will remain a monopolist in the transmission sector even after the

deregulation • => No change of legislation in the deregulated electricity market • EVN has the ability to transport and market the additional generation

throughout the whole country • A single responsible entity does make a system of cost distribution

obsolete • As a single responsible entity no issues of competition distortion will

have to be reviewed

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9. Grid Connection Cost and Obligation Before a wind energy plant starts operation it has to be connected to the electricity grid. In order that each wind energy producer actually gets connected to the grid, a fundamental aspect for a wind energy support scheme is that grid operators guarantee grid access for electricity generated by wind energy. Therefore, in the European Union, Member States may oblige the grid operators to provide priority access for renewable energy producer. It is also recommended for Vietnam to oblige the grid operator to provide access for every wind power plant operator. Consequently the wind energy deployment in Vietnam can not be hampered by refusing of grid access for wind energy farms. (Beside the grid connection obligation it is also recommended obliging grid operators to extend and reinforce their grid - if necessary to accept all electricity generated form wind energy). Grid connections arises costs. The following costs for grid connection may be considered: • Expenses to connect the wind power plant physically to the electricity

grid, • Reinforcement of the grid if the capacity of the local grid is not sufficient

to accept the new installation. A significant contribution of the total capital expenditures is the costs for physical grid connection. Therefore, they have an important impact on the economic viability of a project. Moreover, additional costs can be arising from grid extending and reinforcing. There are three methods identified below to distribute the occurred costs of connecting, extending and reinforc-ing. Shallow connection charging In the case of shallow connection charging, the wind energy producers will pay for the costs of the equipment needed to connect their plant physically to the nearest point of the electricity grid. The costs for reinforcement of the grid will be paid by the grid operators. Usually, the grid operators recover those costs by passing them to the final consumer through system charges. The national regulation on grid operators needs to allow for forwarding such costs. The shallow method of connection charging reduces the costs for plant operators, and allows him a clear and transparent estimation of the expected project cost at an early stage. On the one hand, an advantage of this ap-proach is that producers can choose the location for their wind energy plants based on wind resource potential and need not consider grid availability but only the distance to the next available point of connection. So project developers will seek to place the plant as close as possible to the existing all other things equal. On the other hand this can also be a disadvantage because it may lead to an inefficient choice of plant sites from the grid operator’s perspective and could lead to higher grid reinforcement costs.

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The structure of shallow connection charging is almost similar to the Decision No.18/2008/QD-BCT which describes requirements on grid connection cost and obligation applicable to small renewable power plants. According to Article 4 of Decision 18, the Seller shall be responsible for investment, operation and maintenance of the grid and the electrical trans-former which transforms the power from the power plant of the Seller to the connecting point of the electricity grid of the purchaser. The connecting point to the grid of the purchaser shall be the closest point connecting to the existing grid of the purchaser. The connecting point shall be agreed by the purchaser and the Seller. Where parties fail to negotiate the connecting point, the parties shall form their own opinion for grid connection and submit the same to ERAV for ERAV’s review and settlement. Where the connection point is different from the place of the measuring device, the Seller shall be responsible for the electricity loss occurring in the connecting line. Deep connection charging When the deep connection charging method is applied, wind energy produc-ers have to cover all costs of integrating their plant physically. This includes the costs of the equipment needed to connect their plant physically to the nearest point of the electricity distribution grid and all the cost of reinforce-ment necessary to connect their plant. The grid operators will bear no extra costs from physical wind power integration. On the one hand this approach provides strong incentives to choose loca-tions where costs from grid integration are low. This may lower the whole grid distribution system. On the other hand costs for the wind energy generators will be higher and unclear for grid reinforcement. Therefore this approach could hamper the deployment of wind energy. Mixed or shallower connection charging The concept of mixed or shallower connection charging combines the deep and the shallow method. By applying the mixed or shallower method the wind energy producers will pay for the costs of the equipment needed to connect their plant physically to the nearest point of the electricity distribu-tion grid. Grid operators and wind energy generators will share the costs of grid reinforcement. Usually, the wind energy generator has to pay a share of the costs of grid reinforcements that will arise due to adding the plant to the grid. In this case clear and transparent rules are necessary how to calculate the costs covered by each party. As with the deep connection charging approach, the mixed method gives an incentive to choose locations where the grid has sufficient capacity to accommodate the additional electricity generated from wind energy. The mixed or shallower method of connection charging combines the shallow and deep methods. This approach can be seen as a "compromise" between the two objectives of giving some location incentives and reducing the burden on the producer to pay grid reinforcement costs. Moreover, the higher costs for reinforcement can hamper the deployment of wind energy and could enforce the risk that locations with high wind energy potential are not used.

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In many countries of the European Union, the calculations for renewable energy projects are based on deep connection charging approach. Only Germany, Belgium, Denmark and the Netherlands apply the shallow connection charging method. However, there are considerations of the European Union to implement the shallow grid connection method in all Member States. This would lead to more transparency and planning security for both, the grid operator and renewable electricity generator. In this regard, a grid shall be deemed to be technically suitable even if feeding in the electricity requires the grid system operator to upgrade its grid at a reasonable economic expense. In this case, the grid system operator shall upgrade its grid without undue delay, if so requested by a party interested in feeding in electricity. If the plant must be licensed in accordance with any other legal provisions, the obligation to upgrade the grid in accordance with the second sentence above shall only apply if the plant operator submits either a license/partial license or a preliminary decision. In Germany, the connection obligation shall apply to the grid system operator that is most closely located to the plant site and is in possession of a grid technically suitable to receive electricity if there is no other grid with a technically and economically more suitable grid connection point. If the electrical capacity of the plant is below 30 kW the most suitable grid connection point is the grid connection of the estate it is erected on. The obligation to upgrade the grid shall apply to all technical facilities required for operating the grid and to all connecting installations which are owned by or passed into the ownership of the grid system operator. Costs for grid expansion are burdened by the grid operator, whereas costs for grid connec-tion are borne by the plant operator. In order to give the two interest groups (grid operators and plant operators) a mediatory tool the “Clearingstelle EEG” has been originated. Plant operators must equip their technical facilities with systems that allow the grid operator to reduce remotely the power output in case of grid overcharge and read back the current power output of the plant. In Spain the law provides a connection obligation for plants using renewable energy sources. In terms of priority grid access, the Spanish Wind Energy Association (AEE) confirms that all forms of renewable power generation are granted priority grid access under Spanish law. In the Spanish system the investor of the plant has to pay all the costs related with grid connection (also the costs for grid reinforcement). During the OPTRES17 stakeholder consultation, some respondents questioned whether it is fair that the investor has to pay for all hardware and renewal costs, while ownership of the installations goes to the grid operator. In Spain, the RES-E developers can obtain an estimation of connection costs from the grid operators, as it is required by the Spanish legislation. For Vietnam the shallow connection charging method is recommended. The payment of grid reinforcement by grid operators enables them to plan grid

17 OPTRES (Assessment and optimization of renewable energy support schemes in the European Union) was financed by the European Commission

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extensions and reinforcements at an early stage. Within this process high potential wind sites as well as the actual conditions of the grid and the resultant gird reinforcement and costs for reinforcement could be consid-ered. This approach would limit or reduce the external costs. Since the condition of the grid and the grid capacity influence the deployment of wind energy or renewable energy in general, it has to be ensured that grid charges are sufficient to cover all costs arising due to wind power integration. In addition, the shallow connection charging method ensures is more transparent and planning security for investors.

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10. Institutional Framework for Administration of the Feed-In Tariff Scheme

The introduction of a feed-in tariff scheme for wind energy requires an appropriate institutional framework for its efficient and effective administra-tion. Such a framework comprises the implementing institution assigned with the relevant tasks as well as its interfaces with other institutions in the sector, the organizational set-up of this institution, the scope of its tasks and responsibilities, and the operational procedures for monitoring, reporting, review and compliance measures for the implementation of the feed-in tariff scheme. In the following, we first examine existing and candidate institu-tions, then identify the most appropriate institution, describe its required set-up, and finally comment on monitoring and reporting requirements

10.1 Identification of the appropriate implementing institution

10.1.1 Potential candidates

Several institutions in the power sector of Vietnam already carry out func-tions which are relevant for the recommended feed-in scheme for wind power plants in one way or the other. These are: • three companies within the holding company of EVN:

• Electric Power Trading Company • National Load Dispatch Center • National Power Transmission Corporation

• and the Electricity Regulatory Authority of Vietnam. Furthermore, two new institutions in the field of renewable energy are under planning: • Renewable Energy Development Office; and the associated • Renewable Energy Development Fund. These institutions are potential candidates for an implementing institution for the feed-in tariff for wind power plants. They are described below in more detail. Electric Power Trading Company (EPTC) EPTC is a dependent company under EVN and acts as the Single Buyer in the electricity market. The Prime Minister's Decision No. 26/2006/QD-TTg dated 26 January 2006 approving the roadmap, conditions for establishment and development of electricity market in Vietnam stated that the electricity market in Vietnam will be established and developed in three stages:

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• Competitive electricity generation market (2005-2014); • Competitive electricity wholesale market (2015-2022); • Competitive electricity retail market (after 2022). According to the design of the competitive electricity market, only EPTC, established as the Single Buyer is allowed to purchase electricity from all power generation units in the market and sell electricity to the power distribution companies in the market. EPTC is the focal body for implementation of power purchase agreements (PPAs) and works related to the PPAs in accordance with the scope author-ized by EVN. This concerns renewable energy projects up to 30 MW and all hydro, thermal and renewable power plants above 30 MW. According to Decision No. 125/QD-EVN-HDQT of 28 February 2008, the EPTC is authorized to enter into PPAs with IPPs for all renewable power plants. This is in contradiction to Decision 18/2008 which states that the "Buyer" of Renewable Energy under the Avoided Cost Tariff is a "distribu-tion company". OPEN ISSUE: Authority to buy energy from renewable energy plants EPTC's tasks with relevance for the proposed feed-in tariff include: • Making payments for electricity purchased from power plants. • Agreement on the design of electricity metering system with the project

owner. • Signing PPAs with RE project owners according to the avoided cost

tariffs for Renewable energy plants with a capacity of less than 30 MW. • Agreement on energization for testing and inspection programs, periodi-

cal checking electricity metering systems. • Members of steering committee of independent power producers. • Preparing the format of PPA and submit it to EVN for approval and

promulgation and application by the power plants: thermal power plants, hydropower plants, gas turbines, renewable energy projects.

• Implementing the works for establishment and development of competi-tive electricity market.

• Implementing price offering on behalf of BOT and IPP plants. • Preparing the plan of electricity trading and submitting to the EVN for

approval. • Buying electricity in the spot market, buying electricity from power

plants with PPAs. National Load Dispatch Center (NLDC) NLDC is a dependent department under EVN, with the responsibility for direct dispatch in the power system including power plants with a capacity ≥ 30 MW, power transmission lines at voltage of 66 V to 500 kV and operation of power distribution networks of provincial and urban power

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companies, according to the technical procedures and operation modes determined by regulation. NLDC is involved in development and operation of the internal power market, and the pilot competitive power generation market. It is coordinated with units within and outside the power sector, making comments and contributing to the development of the legal procedures and regulations as the base for the operation of a fully competitive electricity market in the future. NLDC is responsible for upgrading the database for the calculation of the avoided costs tariffs. Every year, before 31st August, NLDC prepares the draft avoided cost tariff schedule and submits it to the ERAV for review and promulgation. National Power Transmission Corporation (NPT) NPT is a one-member limited company in which EVN holds 100% of the charter capital. Its main functions and duties include: • operation, management, repair and of testing power transmission lines at

voltage from 220 kV to 500 kV according to the regulation; • consultancy on investment, • project management, and consultancy on supervision of construction

works of power networks and business on other sectors in compliance with the laws.

NPT is responsible for: • investment, operation and management of the power transmission of the

national power grid;. • preparing and submitting the total revenue of power transmission for the

next year; • preparing and submitting power transmission tariffs payable by genera-

tion units in the next year. Electricity Regulatory Authority of Vietnam (ERAV) ERAV is an organization under the Ministry of Industry and Trade (MOIT), using state budget and fees from electricity operation for its operation. ERAV has many duties and rights, of which the main ones with relevance for RE and wind are as follows: 1. Submit the following regulations to the Minister of Industry and Trade

for approval or promulgation:

• Regulations on conditions, procedures for granting, revising, sup-plementing, withdrawing electricity operation licenses;

• Regulation on procedures for preparation, review and approval of least cost planning and implementation procedures;

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• Regulations on operation of electricity market, including regulation on power transmission network, power distribution network, electric-ity metering, standard power purchase agreement;

• Regulations on methodologies for preparation, procedures of review and promulgation of tariffs in electricity operation in accordance with the laws;

• Regulations on inspection of electricity operation and utilization, re-solving disputes in PPAs.

2. Assist the Minister of Industry and Trade in direction, inspection,

supervision, assessment of, and responsibility for, organizing the im-plementation of laws, legal documents, policies, plans, projects, pro-grams and regulations on electricity issues after being approved;

3. Implementing tasks of electricity regulation and electricity market

operation, including:

• Reviewing power development planning of provinces and cities un-der management of the central government;

• Publishing the list of power generation and transmission projects

which need investment according to the annual plans approved; monitoring implementation of power generation, transmission, dis-tribution in accordance with the power development plans already approved;

• Granting, amending, supplementing, and withdrawing electricity op-

eration licenses; • Issuing tariffs and fees of electricity operation, including the frame-

work of power generation tariffs, electricity wholesale tariffs; power transmission tariffs; electricity distribution tariffs; market transaction costs; costs of power system dispatch; usage fees of auxiliary sys-tems and other costs;

• Approving bilateral PPAs submitted by generators and electricity

purchasers; • Inspecting, monitoring electricity supply and electricity operation in

order to ensure power demand – supply balance; • Proposing measures for encouraging or restricting investment in de-

velopment of power plants, power network projects in order to en-sure long term demand – supply balance and power system operation in stability, safety with reasonable reserve, least costs of production and operation;

• Determining and publishing the ratio between capacity and energy

according to the purchase mode through PPA or on the spot market

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for generating companies at stages of electricity market develop-ment;

• Determining the status of loading of electricity network according to

the request of power generation units;

• Regulating the operations of the electricity market; recommending to the competent authorities on alternatives of emerging or separating electricity operation units in order to ensure transparent competition in electricity market;

• Checking and treating in accordance with its rights the law violation

in implementation of regulation on electricity market operation; elec-tricity operation license; power purchase agreement; electricity tar-iffs and fees; DSM projects, programs and EE&C projects approved and other regulations according to the laws on electricity operation and electricity market.

4. Participating in development of the national power development master

plan; development of the power sector restructuring program and the electricity market model for the Minister of Industry and Trade to sub-mit to the Prime Minister for approval.

5. , Reviewing and approving 1st December every year the avoided cost

tariffs prepared by the NLDC for the next year before; publishing the avoided cost tariffs for the next year on the websites of ERAV and MOIT within 2 days from the date of new tariffs promulgation.

Renewable Energy Development Office (REDO) The Strategy and Masterplan for Renewable Energy Development of Vietnam for the period up to the year 2015 with outlook to 2025, prepared in 2008, identified the need for a single strong and independent central body that can coordinate the actions to promote RE development and rural electrification. The Masterplan's recommendation to create a Renewable Energy Development Office (REDO) and an associated renewable energy development fund was taken up in the MOIT's Letter of Submission to the Prime Minister on approval of the Strategy and Masterplan. The recent draft Decree on encouraging and supporting renewable development also refers to the recommendations.. According to the recommendations REDO will operate under the MOIT, consisting of representatives from related ministries such as Ministry of Science and Technology, Ministry of Finance, Ministry of Natural Re-sources and Environment, Banks. REDO will manage and control RE promotion activities on behalf of the Government. It will have the following functions:

4890S11/FICHT-5530494-v1 10-6

• As consultant for MOIT, acting as the national focal organization for development of renewable energy technologies; representing the gov-ernment in international organizations on renewable energies.

• Developing the RE action strategies, step by step to remove barriers on

policies, mechanisms, finance, technologies, manpower and awareness. • Identifying and assessing the feasibility of potential RE projects in order

to prepare implementation plans. • Developing the financial mechanisms for RE power projects in the off-

grid areas and extremely difficult areas. • Preparation of plans, arrangement of capacity building training programs,

technology transfer, support for commercialization of RE technologies. • Coordinating with the Standardization and Measurement General De-

partment in development of Vietnamese standards on RE equipment. • Managing the database on renewable energies. • Acting as focal point for publishing information documents on RE

technologies. Renewable Energy Finance and Subsidy Fund (REFSF) REFSF is devised as the unit managing fund for supporting RE develop-ment. The Fund will operate without profit according to the mechanism which is developed and promulgated by MOIT and MOC. It will support the following activities: • Science and technology research, development of standards and pilot RE

projects. • Support for feasibility studies, technology transfer, investment and

construction of independent renewable power projects which supply elec-tricity for households in rural remote and island areas.

• Support for domestic productions in order to upgrade quality of renew-able energy equipment and localization rate and mastering renewable energy technologies.

10.1.2 Assessment and recommendation

Then main criteria for selection of the appropriate implementing institution for the wind power feed-in tariffs include competency (does the institution already have responsibilities in the field?), expertise (does the institution have experience and know-how in the field?), and integrity (is the institution free of conflicts of interest?). The Electric Power Trading Company, as the single buyer in the restruc-tured electricity market, can buy electricity bulk from all generators above

4890S11/FICHT-5530494-v1 10-7

30 MW and all renewable power plants participating in the electricity market. As party to the PPA, EPTC would have a conflict of interest and therefore should not be considered as the implementing institution. The only responsibility of the National Load Dispatch Center with regard to renewable energy is the compilation of relevant data and subsequent calcu-lation of avoided cost. Since avoided costs are derived from conventional energy, this does not qualify NLDC for the administration of feed-in tariffs which are based on the costs of renewable energy, in particular wind energy. The key competencies of the National Power Transmission Corporation are concentrated on other fields than renewable energy. NPTC therefore has little competence to act as implementing institution for the feed-in tariff, also it will be involved in the supply of wind energy via its grid. Any other company under the EVN holding is also not the best choice for the implementing institution due to conflict of interest. The calculation results for the remuneration level for wind power projects as presented earlier in this report indicated that the electricity price of wind turbines Vestas V52 which are installed in three sites with a 65m high pole ranges from 0.101$/kWh to 0.144$/kWh, is 3 times higher than the present electric-ity tariffs promulgated by EVN for renewable energy small power plants according to the avoided cost tariffs promulgated in accordance with the Decision No. 18/2008/QD-BCT dated 18 July 2008 by MOIT, which is in effect from 1 January 2009. Because the only single buyer in the market is an EVN company, EVN would have to bear the financial burden of buying wind electricity in order to achieve the national target of renewable electric-ity. Taking this into account, it would be difficult for EVN to be the gov-ernmental focal point for management, purchase and controlling the subsidy for the wind electricity tariff. Because the main function of the Electricity Regulatory Authority of Vietnam (under MOIT) is electricity regulation, it is entrusted with the duty to support development of renewable energies in general and wind power in particular. Therefore, ERAV would be well qualified to act as implementing institutions for the wind power feed-in tariff. The new functions and duties for the feed-in tariff would need to be supplemented. However, ERAV has no experience yet in the management of price subsidies for renewable power projects or programs in accordance with regulations. Therefore capacity building would be required at ERAV. ERAV would be the most appropriate institution for administration of the feed-in tariff for wind power in the absence of a specialized agency for renewable energy. However, since there are plans for establishing a Renew-able Energy Development Office under MOIT, this new office with the function of overall management of renewable energies seems to be the best choice also to administrate the feed-in tariff for wind power.

4890S11/FICHT-5530494-v1 10-8

10.2 Organizational set-up of the implementing institution

10.2.1 Institutional set-up

The REDO will be the central body for coordination of renewable energy projects. It will take over some functions from existing bodies, but some functions will remain with the institutions which are best qualified to carry them out. NLDC would keep the responsibility for calculating the avoided cost tariffs for renewable energy plant, and ERAV would remain responsi-ble for reviewing, approving and publishing all tariffs relevant for renew-able energy projects, including wind power.

10.2.2 Organizational set-up

The Office will have two main divisions (Administrative & Planning and Technical & Economic). The Technical and Economic Division is divided into two departments (Evaluation & Monitoring and Development Tech-niques). OPEN ISSUE: Status of establishment of REDO The proposed structure of the REDO in Vietnam is shown in the diagram below:

4890S11/FICHT-5530494-v1 10-9

Figure 10-1: Proposed structure of the REDO in Vietnam

10.2.3 Functions

The REDO will act on behalf of the Government in the management and control of RE development activities, and will have the following tasks: • Preparing plans, organizing operation of financial fund and support for

RE development, management of RE projects. • Coordinating with related ministries, sectors to submit the national RE

target program to the Prime Minister for approval and implementing the program.

• Coordinating state management activities on renewable energies between ministries, sectors and localities.

• Guiding on implementation of the RE projects for enterprises and on preparation of feasibility reports, administrative procedures, loans…

• Promulgating regulations on organization of consultancy activities, checking products, organizing tenders.

• Review, assessment and approval of the proposed RE projects. These tasks as already proposed should be supplemented with the specific tasks associated with the feed-in tariff:

Ministry of Industry and Trade

(MOIT)

Director of Office

Ministry of Finance (MOF)

Bank Ministry of Natural

Resources and Environment

Division of Ad-ministrative and

Plan

Division of Tech-nical and Eco-

nomic

Evaluation and Monitoring

Development Techniques

- Monitoring and technical support for Renewable Energy projects - Develop Technical standards for Renewable Energy - Training, Refresh training, technique management

- Develop strategies, policies, financial institutions and technology - Identify and assess project feasibility NLTT - Feed-in Tariff Setting, Design and Management

- The administrative works of Office - Print publishing and propaganda - Logistics

4890S11/FICHT-5530494-v1 10-10

• Developing and managing feed-in tariffs for RE projects by different

groups of technologies, by localities which have potential of renewable energy resources. Every year, REDO shall adjust feed-in tariffs suitable to the actual conditions, such as

• Scientific and technological progress • Price fluctuation of raw materials • Slippage in foreign exchange rates • Slippage in price of VND • Change of bank interest • Adjustment of the annual labor price, etc.

OPEN ISSUE: Structure of Feed-in Tariff

10.2.4 Staffing

At this stage, coordination of renewable energy is a new field of manage-ment with a lack of human resources and experience. So it will be necessary to develop human resources with awareness of technology, economics, program management, identification and evaluation of RE projects. It is expected that the REDO will have a staff of [….], covering expertise in all renewable energies, including wind. OPEN ISSUE. Staffing and budget of REDO [Section to be amended.]

10.2.5 Funding and budget

The administrative budget for the REDO (salaries, rent etc.) is estimated at VND [……] annually. It will be covered by the Renewable Energy Finance and Subsidy Fund (REFSF) which is planned to be set up in connection with REDO. OPEN ISSUE. Staffing and budget of REDO The REFSF which will manage the funds for RE development. The finan-cial resources for this fund will come from the following resources: • Additional fees on natural resources (fossil fuels such as coal, oil, gas).

This fee is proposed for restricting ineffective exploitation and saving of these energy resources.

• Fees collected from emission of pollution in process of electricity production.

• Revenue of selling GHG emission reductions (applied only for projects with get support from the RE development fund)

4890S11/FICHT-5530494-v1 10-11

• From other resources: State budget, international donating organizations, etc.

The budget for this fund is calculated based on the roadmap of annual, long term and medium term plans of RE development, suitable fees from the above mentioned source in order to ensure achieving targets of RE devel-opment. In case the budget is not fully used in one year, the remaining amount shall be deposited in banks and their principal and interest portions shall be used for supporting RE projects in the sequent years.

10.2.6 Cash flow

An additional task of the REFSF, not yet considered in the proposal of its establishment is to provide a price subsidy for renewable power plants operating under the feed-in tariff for wind or the avoided cost tariff for renewable energy projects in general. The avoided cost tariff (ACT) cur-rently applied to all small renewable energy projects is also a type of feed-in tariff (FIT), but it is based on the avoided cost of conventional energy, while the proposed FIT for wind energy is based on the costs of providing wind energy. With regard to the subsidy for wind energy, we suggest to use the difference between FIT and ACT to be covered by RE Funds. The use of ACT as reference is straight forward, as it will be calculated and published by ERAV annually, and PPAs for all other RE projects are signed under this tariff. This is transparent and clear for the investors as well as for other stakeholders. Depending on the comparative level of ACT and average generation tariff this subsidy may correctly reflect the additional cost of the buyers of wind energy ; but it would be difficult to base the subsidy on average generation costs, because the background for their calculation is not very transparent. OPEN ISSUE: Subsidy There are several possible ways of directing the flow of funds for renewable energy projects (including wind) under a renewable energy feed-in tariff (ACT as well as FIT for wind), in the following called REFIT: • The buyer of renewable energy (a company under EVN) pays the seller

(the renewable energy power generator REPG) the full feed-in tariff and recovers the subsidy from the REFSF. The REPG passes any revenues from certified emission reduction (CER) on to the REFSF.

• EVN pays a lower tariff than the full feed in-tariff (level to be agreed) to

the REPG and passes the endorsed invoice on to the REFSF which then pays the difference between this tariff and the feed-in tariff to the REPG. This also requires that the REPG passes any revenues from CER on to the REFSF.

4890S11/FICHT-5530494-v1 10-12

• EVN pays a lower tariff than the full feed in-tariff into an escrow ac-count. The REPG is remunerated at the full feed-in tariff by the REFSF taking the funds from the escrow account as well as from the REFSF's funds.

• EVN pays the REPG the full feed-in tariff. The REPG passes any

revenues from CER on to EVN, so that EVN's financial burden is re-duced. The remaining difference is partially or fully recovered from the REFSF.

The first option involves some risk for EVN, but EVN is in a better position to take the risk of non-payment than an REPG. A split payment from two different sources increases the administrative burden as well as the risk of non-payment by one of the sources; therefore the second option is sub-optimal. The third option also involves some risk for the wind generator, as long as the RFSF does not have a secure funding base. The fourth option has the disadvantage that the CERs are traded between buyer and seller on a decentralized level without involvement of the REFSF. OPEN ISSUE: Environmental Attributes The figure below visualizes the first option.

Figure 10-2: Cash flow between key parties

Ministry of Industry and Trade

(MOIT)

Renewable Energy Development Office

(REDO)

Renewable Energy Finance and Subsidy

Fund (REFSF)

Electricity Regulatory Authority of Vietnam

(ERAV)

Renewable Energy Power Generator

(REPG)

Electricity of Vietnam

(EVN)

Subsidy (

Full Feed-in Tariff

CER

4890S11/FICHT-5530494-v1 10-13

10.3 Monitoring, Reporting and Review

The figure in the following shows the key parties involved, their role in the support mechanism and the reporting structure.

Figure 10-3: Key parties involved and their role in the support mechanism

Renewable Energy Development Office (REDO) The REDO shall be responsible for overall monitoring and review, includ-ing: • Data on the energy purchased under the Renewable Energy Feed-in

Tariff (REFIT) per technology band and the total cost of the REFIT, which shall be gathered and maintained by the REDO.

• To prevent over subscription of REFIT, the REDO shall be permitted to bring in capacity limits on specific technologies in the future and priori-tize the types of technology that have a lower Feed-in Tariff.

• The REDO shall be responsible for monitoring the operation of the Renewable Energy Finance and Subsidy Fund.

• By 1st June every year after the implementation of these guidelines, the REDO shall publish a summary report on the progress achieved. This report shall include the following:

• Progress on the 2015 Renewable Energy Target and future national

renewable energy targets;

Ministry of Industry and Trade

(MOIT)

Renewable Energy Development Office (REDO)

Renewable Energy Finance and Subsidy

Fund (REFSF)

Electricity Regulatory Authority of Vietnam

(ERAV)

Renewable Energy Power Generator

(REPG)

Electricity of Vietnam

(EVN)

Generation Licence, reporting on performance

Electricity Money under Avoided cost Tariff (ACT)

PPA

Money (REFIT- ACT)

Reporting on performance and overall Avoided

Costs

Reporting on performance

Rep

ortin

g on

per

form

ance

Reporting on spending

Monitoring on spending

4890S11/FICHT-5530494-v1 10-14

• Update on the market introduction of the qualifying technologies including number of applications received, number of applications ap-proved and number of projects implemented, detailing technology, size and geographic location;

• Financial impacts of the REFIT including the additional overall cost to electricity consumers and average percentage increase on electricity prices;

• Changes or additions in qualifying technologies. Renewable Energy Finance and Subsidy Fund (REFSF) • Every three months, the Renewable Energy Finance and Subsidy Fund

(REFSF) shall publish a summary report on the receipt and expense situation of Fund.

• Every year, the REFSF shall publish a report finance situation of Fund and make plans for spending next year.

Electricity Regulatory Authority of Vietnam (ERAV) • The Electricity Regulatory Authority of Vietnam (ERAV) shall be

responsible for overall reporting of the electricity production from re-newable energy sources to the REDO.

• The ERAV shall liaise with EVN and the National Load Dispatch Centre to monitor dispatch issues arising from the connection and generation of power under REFIT.

• The ERAV shall monitor and report to perform a Power Purchase Agreement between EVN and Renewable Energy Power Generators (Electricity Price, Capacity, Capacity Diagram, and Electrical Energy Production).

• Every year after the implementation of these guidelines, the ERAV shall publish a report on the progress achieved. This report shall include the following in addition to the requirements of the REDO progress report described above: • Cost development and learning effect resulting from the market ex-

pansion of the technologies. Renewable Energy Power Generators • REPGs are required to adhere to the Vietnam Grid Code and Vietnam

Distribution/transmission Grid Code regarding planning information, operational information and post-dispatch information.

• REPGs must be periodically report device status, capacity and electrical energy production, the problem of managing and operating arise in prac-tice and sent to ERAV.

• In addition to the monitoring and reporting requirements under the Generation License conditions, REPGs are obliged to submit annual re-newable energy generation reports to the Regulator by 1st February of the following year. The report shall detail: • The net maximum capacity of the renewable energy generation (MW); • The renewable energy sent out by the REPG(MWh); • Comments and feedback on the progress and success of the REFIT

from the perspective of the REPG.

4890S11/FICHT-5530494-v1 10-15

OPEN ISSUE: Reporting obligations Electric Power Trading Company (EPTC under EVN) • EPTC shall monitor and report on power production by RE Power

Generators to the Regulator. • By 30th November each year, EPTC in conjunction with the Regulator

shall be required to prepare a projection on the estimated take up of new connections and power generation for the following year.

• By 31st March each year EPTC shall be obliged to report to the Regula-tor the cost of the energy purchased under REFIT over and above Avoided Cost and all additional costs associated with the implementation of REFIT, including Wheeling Charges and costs incurred in the man-agement and implementation of REFIT by EPTC.

4890S11/FICHT-5530494-v1 10-16

Reporting Institution

Addressee of Report

Subject of Report Frequency of Report

Renewable Energy Develop-ment Office

General public

• Summary report on the progress achieved • Cost development and learning effect

resulting

Twice a year

Renewable Energy Finance and Subsidy Fund

REDO

• Summary report on the receipt and expense situation of Fund

• Budget for next year

Four a year

Electricity Regulatory Authority of Vietnam

REDO

• Electricity production from renewable energy sources

Once a year

Renewable Energy Power Generators

ERAV • Device status, capacity and electrical energy production, problem of managing and operating arise in practice

Twice a year

• Net maximum capacity of the renewable energy generation (MW);

• Renewable energy sent out by the RE Generator (MWh);

• Comments and feedback on the progress and success of the REFIT from the per-spective of the RE Generator

Once a year

Electric Power Trading Com-pany

ERAV • Power production by RE Generators • Projection on the estimated take up of

new connections and power generation for the following year

• Cost of the energy purchased under REFIT over and above Avoided Cost and all addi-tional costs associated with the implemen-tation of REFIT, including Wheeling Charges and costs incurred in the man-agement and implementation of REFIT

Once a year

Table 10-1: Monitoring and reporting requirements

4890S11/FICHT-5530494-v1 11-1

11. Tariff Funding Requirements

11.1 Additional costs

This chapter describes the development of the total remuneration paid to wind power plants over the period till 2025 and the resulting additional costs. We assume that the targets of the Draft Master Plan for Renewable Energy Scenario 4 will be entirely met through the implementation of the feed-in regulation. Thus, 564 MW of wind power plants will be installed by 2015 and 629 MW by 2025. Particular on the long, i.e. after 2015 we may see a much faster pace of wind power deployment in Viet Nam once a dynamic development has been triggered and wind power is accepted as bulk elec-tricity provider. We thus assume that by continuing the pace until 2015 also afterwards, the 2025 target will be already met in 2016. Since the initial tariff of 10.5 US cents/kWh is particular economical viable for the very best wind power plant sites we assume average annual full load hours of 3030 hrs/year, equivalent to a capacity factor of 35%. As a result, there will be an annual generation of 1.9 TWh of wind power after 2016. For wind power plants erected in 2010 or before, the specific remuneration will be 10.5 US cents/kWh. This tariff will be lowered by 1.6% each year for the vintages of wind power plants erected later. So wind power plants erected in 2016 will only receive a remuneration of 9.53 US cents/kWh. As a result the average remuneration for all wind power generated falls to 10.0 US cents/kWh by 2016. The total annual remuneration paid to wind power plants increases from 9.54 million USD in 2010 to 190.24 million USD in 2016 staying then constant afterwards (Figure 11-1).

Annual Remuneration of Wind Power Plants

0

20

40

60

80

100

120

140

160

180

200

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mill

ion

USD

Figure 11-1: Development of total annual remuneration of wind power according the feed-

in regulation.

4890S11/FICHT-5530494-v1 11-2

This amount of remuneration needs to be compared to the value of the power generated. At the moment, there does not exist any market prices for power in general and for wind power in particular. Therefore, we used • The Avoided Cost Tariff according to Decision No. 18/2008/QD-BCT

and Decision No. 74/QD-DTDL. We assume that this tariff is to be in-creased by 3% every year.

• The Average Weighed Marginal Costs for the period 2006 till 2025 according to the Power Development Plan VI. Again, we assume an an-nual increase of marginal costs by 3%, i.e. the weighted marginal costs will be only 6.4 US cents/kWh in 2010, but 9.9 US cents by 2035. We do not consider any credit for the capacity since the scale of value for the particular case of Viet Nam is very uncertain at this point.

• In addition we calculate the potential revenues from selling Certified Emission Reduction (CERs) at a constant price of 15 USD/t CO2

• In addition we estimate the external benefits of wind power generation beyond green house gas mitigation at 0.1 US cents/kWh. This estimate of IoE might be regarded as the low end of possible external costs of con-ventional power generation.

Initially the additional costs will amount to 6 million USD in 2010 and will reach the maximum in 2016 with 114 million USD (Figure 11-2). Since the specific value of Avoided Costs Tariff will increase constantly over time and no further growth of wind power under the feed-in regulation is as-sumed after 2016, the total additional costs will decrease after 2016. These additional costs are the costs which need to be covered by surcharges or others. This assumes that revenues from CER will be used to finance part of the total remuneration.

6

28

49

69

87

105

114 111113 109 107 105 103 101 99 97

0

20

40

60

80

100

120

140

160

180

200

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mill

ion

USD

Additional CostsCER RevenuesAvoided Cost Tariff

Figure 11-2: Composition of cost coverage of total remuneration. Here we compare

against the Avoided Cost Tariff, the value of Certified Emission Reductions and external benefits. Resulting additional costs are given in red with the val-ues on the top of the bars giving the exact value of the additional costs for each year.

4890S11/FICHT-5530494-v1 11-3

One can estimate the additional costs to society, if one compares the total remuneration with the Weighed Marginal Costs of power generation i.e. the power generation costs of new power plants (Figure 11-3). Then the value of wind power generation is rated much higher so that the additional costs are substantially lower. After 2020 the value of wind power generation is even higher than the remuneration according to the feed-in tariff leading to net gains.

3

11

18

23

25

26

24 1520 10 6 1-4 -9 -15 -20

-50

0

50

100

150

200

250

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mill

ion

USD

Additional CostsAvoided External CostsCER RevenuesAvoided Marginal Costs

Figure 11-3: Composition of cost coverage of total remuneration. Here we compare

against the Avoided Marginal Costs (brown bars), the value of Certified Emission Reductions (light blue bars) and external benefits (green bars). Re-sulting additional costs are given in red with the values on the top of the bars giving the exact value of the additional costs for each year.

4890S11/FICHT-5530494-v1 12-1

12. Sources of Finance The feed-in tariff will cause additional costs. The additional costs will be comparatively low at the beginning but may increase over time with more and more renewable energy deployment triggered. To prevent excessive burdens for Vietnam through the feed-in tariff, feasible financial schemes should be implemented to cover the extra costs resulting from the feed-in tariff.

12.1 Vietnam Environmental Protection Fund (VEPF)

The Vietnam Environmental Protection Fund (VEPF)18 was established according to Prime Minister Decision No. 82/2002/QD-TTg of June 26, 2002. Decision No. 35/2008/QD-TTg of March 03, 2008 outlines details regarding the organization and operation of VEPF. It is a governmental financial organization attached to the Ministry of Natural Resources and Environment and financially managed by the Minis-try of Finance. The fund was established to support environmental protec-tion activities in Vietnam. It operates on a non for profit basis, however, must ensure the retrieval of its chartered capital (currently VND500 billion from National Budget) and the coverage of managerial expenses. Additional capital is mobilized from other sources like: • Environmental protection fees of wastewater, gas emission, solid wastes,

mineral exploitation • Compensations for environmental damages, • Administrative fines for infringing environmental protection law, • Fees for selling/exchanging CERs • Sponsors, support, contributions, entrust investment of organizations,

individuals inside and outside Vietnam • Supplementary capitals according to legal laws In general the fund provides financial support for programs, projects and activities related to natural and biodiversity conservation and prevention measures, to combat and remedy national, inter-branch or inter-regional environmental pollution, deterioration and incidents or settlements of local environmental issues which have great impacts. For these measures the following support could be provided: • Provides loans with preferable interest rates; • Provides lending interest rate support when capital is borrowed; • Provides guarantees for environmental projects loan from credit organi-

zation;

18 http://vepf.vn/Home

4890S11/FICHT-5530494-v1 12-2

• Provides financial support for a number of environmental protection agencies and tasks as prescribed in the Regulation on organization and operation of the fund; and

• organizes the registration, monitoring management and fee collection of selling/exchanging Carbon Emission Reductions

Regarding VEPF's responsibility in the CDM the following activities are conducted: • To register, monitor, manage CERs granted by CDM EB; • To collect fees of selling/exchanging CERs; • To spend on support of dissemination and propaganda operations of

CDM; • To establish, set up, appraise and approve investment project documents

in compliance with the CDM; • To manage and monitor the implementation of CDM project and other

CDM concerned purposes in compliance with the law, conducting price support for products of CDM project as stipulated by the law.

In essence, VEPF at the moment provides assistance with soft loans for environmental projects in Vietnam. It further offers subsidies for prod-ucts from CDM projects (e.g. subsidies for power generated from wind energy projects; see Decision 58/2008/TTLT-BTC-BTN&MT and dis-cussion further below). The Fund therefore addressed wind power pro-ject investments but only in the context of the CDM. VEPF is currently thinking about the possibilities of setting up annual award systems for environmental project as well as a mechanism according to which pre-mium tariffs for renewable energy projects could be considered in the near future. We conclude that VEPF has currently a central role in managing the CERs from CDM projects and provides subsidies on products from re-newable energy projects among others wind energy projects. At the moment the monies provided for the subsidies comes from the CER col-lection fees and the overall available budget. VEPF has received from the government. In a new system, where special feed in tariffs for re-newable energy projects will be defined, the existing subsidy system would need to be changed as otherwise there will be a double incentive system that would not be feasible. One possibility to refinance the bonus tariffs (the additional costs), how-ever, could potentially remain with VEPF, as the Fund already covers these costs in the present subsidy scheme. In consultation with VEPF, the Fund has mentioned that it is considering bonus electricity tariffs from renewable energy projects in the near future. The Fund therefore is one major potential player to discuss refinance modalities for newly set of renewable energy tariffs.

4890S11/FICHT-5530494-v1 12-3

12.2 Surcharges

Any additional surcharge on top of existing surcharges and taxes represents an additional financial burden. To refinance the costs associated with the promotion of wind power projects surcharges may be imposed for private households and/or commercial businesses purchasing grid power. Decision No. 21/2009/QD-TTg of February 12, 2009 was published by the Prime Minister on electricity sale prices in 2009 and during 2010-2012 under market mechanisms. Year Specification of electricity sales

price Comment

2009 Average retail price of electricity is VND 948.5/kWh

Price exclusive of value added tax, price increase by 8.92 % compared to average price in 2008

From January 1, 2010

Electricity prices shall accord with market prices. To apply two-constituent prices including (i) capacity price and (ii) electricity price

Two-constituent prices to be applied in appropriate localities where technical conditions permit.

Table 12-1: Specification of electricity sales price according to Decision No. 21/2009/QD-TTg

The average retail price is adjusted as follows: Year Specification 19 Comment In 2009 Price subsidy 35-40% of average sales

price (adjusted progressive price) for first daily 1- 50 kWh

Fichtner's own calcula-tion: the subsidy range would result in an electricity price range of VND 569.10/kWh to VND 616.53/kWh

In 2009 No price subsidy, average cost price is applicable between 51-100 kWh of daily-life electricity

VND 948.5/kWh

Table 12-2: Adjustment of electricity sales price according to Decision No. 21/2009/QD-TTg

We distributed the additional costs as depicted in Figure 11-2 on the total power demand according to the Power Development Plan VI, base scenario. The surcharge then amounts to a maximum of 0.0006 USD/kWh consumed in 2015 (Figure 12-1). That would increase the present average retail price by a maximum of 1.2%. One may also solely put the additional burden from the remuneration of wind power on private households to shield industry from competitive disadvantages. In this case, the surcharge would amount to a maximum of 0.0018 USD/kWh consumed in 2015, which is equivalent to 3.3% of present power tariffs. In both cases the increase of power tariffs over a period of 5 years would be very modest.

19 As per Decision No.21/2009/QD-TTg dated February 12, 2009

4890S11/FICHT-5530494-v1 12-4

Development of Surcharges

0.0001

0.0006

0.0004

0.00030.0002

0.0007

0.0010

0.0013

0.0016

0.0018 0.0017

0.0016

0.00150.0013

0.00130.0011

0.00100.0010

0.00090.0008

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

0.0016

0.0018

0.0020

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

USD

/kW

h

Surcharge on total power consumption

Surcharge on household consumption only

Figure 12-1: Development of surcharges on power consumptions due to additional costs

from wind power remuneration.

12.3 The Global Environment Facility

The Global Environment Facility (GEF) is a global partnership among 178 countries, international institutions, non-governmental organizations (NGOs), and the private sector to address global environmental issues while supporting national sustainable development initiatives. The GEF provides grants for projects related to six focal areas among others climate change. The GEF is also the designated financial mechanism for a number of multilateral environmental agreements (MEAs) or conventions; as such the GEF assists countries in meeting their obligations under the conventions that they have signed and ratified. In particular, GEF projects in climate change help developing countries and economies in transition to contribute to the overall objective of the United Nations Framework Convention on Climate Change (UNFCCC). As the financial mechanism of the UNFCCC, GEF allocates and disburses about USD 250 million dollars per year in projects in energy efficiency, renewable energies, and sustainable transpor-tation. Moreover, it manages two special funds under the UNFCCC — the Least Developed Countries Fund and the Special Climate Change Fund.

12.3.1 Projects funded in Vietnam

In principle, GEF supports projects in Climate Change Mitigation, reducing or avoiding greenhouse gas emissions in the areas of renewable energy, energy efficiency, and sustainable transport. GEF support helps create enabling policy frameworks, build the capacity for understanding and using the technologies, and establish financial mechanisms to make renewables more affordable.

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The GEF helps developing countries to submit national communications to the UNFCCC, including a report on national inventories of greenhouse gases. The largest part of GEF support for the national communications is delivered through an umbrella and support program administered by the United Nations Development Program and United Nations Environment Program. Through this umbrella program, countries can also receive support for vulnerability and adaptation assessments, capacity building, and tech-nology needs assessments. Vietnam has benefited so far from support by GEF for climate change related activities. The following national projects were approved:

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Project name GEF Agency

Project type GEF grant ( US$)

Co-financing (US$)

Project Status

Enabling Activities for the Preparation of Initial Communication Related to the UNFCCC

UNEP Enabling Activity

212,500 50,000 Project Closed

Systems Efficiency Improvement, Equitization and Renewables (SEER) Project - Renewables Components

IBRD Full Size Project 4,500,000 9,500,000 Project Comple-tion

Demand-Side Management and Energy Efficiency Program

IBRD Full Size Project 5,500,000 13,720,000 Under Implemen-tation

Energy Efficiency Public Lighting (VEEPL) Project

UNDP Full Size Project 3,000,000 12,383,000 Under Implemen-tation

Expedited Financing for Interim Measures for Capacity Building in Priority Areas (Phase II)

UNEP Enabling Activity

100,000 -

Under Implemen-tation

Promoting Energy Conservation in Small and Medium Scale Enterprises (PECSME)

UNDP Full Size Project 5,469,000 23,428,250 Under Implemen-tation

Rural Energy II IBRD Full Size Project 5,250,000 273,840,000 Project Comple-tion

Hanoi Urban Transport Development IBRD Full Size Project 9,800,000 328,890,000 Project Comple-tion

Climate-resilient Infrastructure Planning and Coastal Zone Development

ADB Full Size Project 3,400,000 176,960,000 Council Approved

Vietnam Clean Production and Energy Efficiency Project

IBRD Full Size Project 2,374,407 101,500,000 Council Approved

Phasing out Incandescent Lamps through Lighting Market Transformation in Vietnam

UNEP Full Size Project 3,025,000 7,750,000 PGG Approved

Subtotal 42,630,907 948,021,250 11 Projects Table 12-3: Related projects funded under GEF in Vietnam The above list includes several projects that touch on the promotion of renewable energy/energy efficient technologies. Other projects with similar content like promoting wind energy projects in Vietnam but that are implemented in other geographical regions are for example:

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Project name Beneficiary

countries GEF Agency Project description GEF grant (

US$) Co-financing (US$)

Project Status

Financing Energy Efficiency and Renewable Energy Investments for Climate Change Mitigation

Bulgaria, Belarus, Kazakhstan, Macedonia, Romania, Russian Federation, Ukraine, Serbia

UNEP (GEF-Trust Fund)

This project is designed to establish a dedicated financial facility for energy efficiency and renewable energy in Eastern Europe and CIS that can serve as a vehicle for the large-scale participation of private sector investors in partnership with public entities. The proposal is to support the development of a US$ 250 million public-private equity Fund that will be able to complement other funding schemes (including those implemented or contemplated by the GEF and/or other supporting institutions) and, as a result, leverage an investment volume of up to US$ 2 billion for energy efficiency and renewable energy projects.

3,000,000 9,260,000 Under Imple-mentation

IND Financing Energy Efficiency at Small and Medium Enterprises - under the Programmatic Framework for Energy Efficiency

India IBRD - The World Bank

To systematically support the development of a large number of EE investment proposals and create a mechanism of identifying, preparing and financing, these proposals at the local level. This project will build upon the success of the recently completed World Bank Global Technical Assistance project "Developing Financial Intermediation mechanisms in China, India and Brazil" which resulted in launching of five pilot lending schemes for EE at SMEs by Indian banks.

11,300,000 57,500,000 Council ap-proved

Table 12-4: Related projects funded under GEF in other geographical areas

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12.3.2 Project types eligible for GEF funding

Full-Sized Projects (FSPs): are projects over 1 Mio US$. Project concepts may be developed by project governments, non-governmental organizations, communities, the private sector, or other civil society entities, and must respond to both national priorities and GEF focal area strategies and opera-tional programs, and must satisfy eligibility requirements under the Conven-tions. Project proponents work closely with national GEF Operational Focal Points (who formally endorse project concepts) and the GEF Agency, to develop concepts and move through the project cycle. FSPs are subject to project review criteria and are approved by the GEF Council. Medium-Sized Projects (MSPs): are projects up to 1 Mio US$ GEF Funds. offer opportunities for a broad range of programming that is typically smaller in scale than full-sized projects and follow expedited procedures for their approval. Their approval is delegated by the Council to the CEO, and it is subject to project review criteria, similar to FSPs. Enabling activities: Enabling activities relate to the various Conventions the recipient country is party of. With regards to climate change, the preparation of overarching activities like the preparation of national inventories, strate-gies, action plans and reports under this convention are supported. Programmatic approach: Programmatic Approaches represent a partnership between country/ies, the GEF and other interested stakeholders, such as the private sector, donors and/or the scientific community. This approach secures larger-scale and sustainable impact on the global environment, than a single FSP or MSP, through integrating global environmental objectives into national or regional strategies and plans using partnerships. A program usual contains several projects that are linked through common objective/s of the program aimed to foster increased horizontal and vertical integration of global environmental issues into the country/ies development agenda. The preparation of PAs is guided by the Council paper “From Projects to Programs: Clarifying the Programmatic Approach in the GEF Portfolio". (See also the Joint Summary of Chairs for additional comments on the paper in the April 2008 Council Meeting).

12.3.3 The GEF project cycle

Each GEF country member has designated an officer responsible for the GEF activities, known as GEF Operational Focal Point that has a key role in assuring that the GEF projects are aligned to the needs and priorities of his/her respective country. Any eligible person or entity may propose a project. In order a project proposal can be taken into consideration, it has to fulfill the following criteria:

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- It is undertaken in an eligible country (list of eligible countries); - It is consistent with national priorities and programs; - It addresses one or more of the GEF focal areas, improving the

global environment or advance the prospect of reducing risks to it; - It is consistent with the GEF operational strategy; - It seeks GEF financing only for the agreed incremental costs on

measures to achieve global environmental benefits; - Involving the public in project design and implementation; - Is endorsed by the government(s) of the country(-ies) in which it will

be implemented. Before drafting the project proposal the applicant should contact the Coun-try Operational Focal Point and verify that his/her proposal complies with the criteria mentioned above. If there are doubts about the eligibility of the project it is advisable to have an informal consultation with the GEF Secre-tariat (Country Relation Officers in the External Affairs team). The Country Operational Focal Point in Vietnam is: Name Contact Point Dr. Nguyen Van TAI(Council Member/Operational Focal Point)

Deputy Director General Ministry of Natural Resources and Environment 83 Nguyen Chi Thanh Street Hanoi Vietnam Tel: 011 84-4-773 4985/773 5084 Fax: 011 84-4-773 4245

Mr. Pham Khoi NGUYEN(Political Focal Point)

Vice Minister Ministry of Natural Resources and Environment 83 Nguyen Chi Tanh Street Hanoi Vietnam Tel: 011 84 4 7733929 Fax: 011 84 4 7734245 EMail: nvtai@yahoo.com

Table 12-5: GEF Operational Focal Point in Vietnam GEF Agencies assist eligible applicants in the development, implementa-tion, and management of GEF projects. They are the channel between countries and the GEF for the project approval process and participate in the GEF governance as well as in the development of GEF policies and pro-grams. A potential project proponent has the choice on the Agency and such choice should be based on its respective comparative advantages as stated in the document "Comparative Advantages of the GEF Agencies” (GEF/C.31/5rev.1,2007) Once these preparatory steps are taken the proponent should develop the Project Identification Form (PIF), in close coordination with the GEF Agency and following their internal project cycle procedures. Once the PIF is ready the Agency will submit it to the GEF Secretariat for approval.

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The PIF format requires the following major items to be addressed: • Project title • GEF Focal Area and GEF-4/-5 Strategic program • Indicative calendar and milestones • Project objective • Breakdown of project components, their expected outcomes/outputs and

indicative GEF and Co-financing.20 • Total project costs • Project justification for each component 21 • Description of project consistency with GEF Strategies and strategic

programs • Outlining the coordination with other related initiatives in the country • Indicating risks that might prevent the project from being implemented • Expected cost effectiveness of the project • Justification of the comparative advantage of the GEF Agency • Approval endorsement by GEF Operational Focal Point(s) and GEF

agencies & GEF Agency's Certification

12.3.4 Summary GEF funds

GEF money is not available per se to cover the additional expenses of the government in connection with providing special renewable energy tariffs for wind. Vietnam may access GEF money only on a specific project basis. For instance, the implementing arm of the renewable energy tariff system for wind in Vietnam (MOIT, EVN or other) does look into PoA project development and could prepare a proposal for PoA and CPA developments to be discussed in a next stage with the Country Operational Focal Point in Vietnam regarding eligibility. The transaction costs for getting a PoA properly developed and running are quite considerable and may be in the range of several hundred thousands € including all stages, like PDD devel-opment, Validation, Registration fee, annual monitoring and annual verifica-tion. The way forward could be to • Prepare a PIF using GEF format • Consult GEF Country Operational Focal Point and discuss PIF for

getting confirmation on general eligibility • If positive reply, select an implementing/executing agent to GEF and

discuss the way forward to submit full project proposal to GEF, identify co-funding component (by whom and how provided)

• Await approval from GEF

20 Co-financing from approved or implemented projects in Vietnam is typically provided by MONRE, MOIT, MOST, EVN and could be in form of cash and/or in-kind 21 In case wind power projects will systematically be developed as a PoA, possible components that lead to expenditures would e.g. include: a) Development of the entire PoA project cycle, b) provision of a bonus tariff.

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• Implement the project It should be noted that GEF funded projects require a co-contribution from outside that is typically higher than 50% of the financing provided by GEF. So, national contribution to project financing would be required.

12.4 Clean Development Mechanism

12.4.1 Registration of wind power projects under the normal CDM

Under the normal CDM, individual wind power projects can be registered either as small-scale projects using AMS I D baseline and monitoring methodology or as normal scale projects using ACM0002 baseline and monitoring methodology. In Vietnam, the first wind power project was registered as a CDM project on April 6, 2009.

Project 2228 : Wind Power Plant No.1 - Binh Thuan 30MW. The project is a wind farm with 20 individual turbines with 1.5 MW in-stalled capacity each. Project participant is Vietnam Renewable Energy Joint Stock Company (REVN). This project is "first of its kind" in Vietnam and demonstrates additionality by means of investment analysis. In addition to the Base Electricity Tariff (720 VND/kWh) the project currently receives a Subsidy Electricity Tariff of 480 VND/kWh for the investment payback period, which was determined at 12 years. There is currently no other wind power project under CDM Validation phase for which consistency of the base and bonus tariff can be checked. Additionality was demonstrated by the project activity by means of invest-ment analysis excluding the subsidy tariff. According to EB 22 Annex 3, national policies implemented since the adoption by the COP of the CDM M&P (decision 17/CP.7, 11 November 2001) need not be taken into account in developing a baseline scenario. The Vietnamese Government introduced the subsidy in order to promote the CDM and reduction in GHG emissions. This IRR analysis is therefore conservative. Tax and depreciation have also been excluded from the IRR analysis, as per Annex 35 of EB 39 Meeting in May 2008. As per Article 16, item 2 of the Prime Ministers decision 130/2007QD-TTg (dated 2/8/2007), this subsidy is provided by the Ministry of Finance. The subsidy tariff represents a governmental incentive without which the project was argued to not have been realized. In practical terms the project-by-project CDM approach could be used by any subsequent wind power project unless these projects can provide sufficient justification on additionality and unless the CDM guideline and

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Subsidy level per unit

Actual production costs per unit

Planned profit per unit

Actual selling price per unit

Yearly subsidy amount

Subsidy level for each unit in respective year

Quantity of products sold in respective year

Actual incomes from CERs selling

procedures do not change. If an electricity tariff for wind power is set up other than was applicable for the above registered CDM project, this tariff / bonus would be excluded from the investment analysis. We have reviewed Decision no 58/2008/TTLT-BTC-BTN&MT dated July 04, 2008. Item III outlines the subsidy policy to products of CDM projects. Among others, electricity produced from wind power enjoys subsidy policy from VEPF. A subsidy can be provided if the actual production costs for each unit (here it would refer to kWh as unit) are higher than actual selling price in the signed contract. The subsidy level for each product unit (here sold electricity) is based as follows: = + - Formula 1: Subsidy level for each product unit (applicable among others for wind power projects) The required annual subsidy amount is calculated as follows: = * - As an example, the registered CDM wind project Wind Power Plant No.1 - Binh Thuan 30MW received a subsidy in the range of two thirds of the base tariff (base tariff: 720*10³ VND, subsidy: 480*10³ VND) The subsidy for wind power projects developed under the CDM remains valid until otherwise decided by the Ministry of Finance / Ministry of Natural Resource & Environment in the future. As discussed in the Chapter of VEPF, adjustments to this subsidy systems may take place once a new electricity fed in tariff for wind power projects will be implemented.

12.4.2 Registration of wind power projects under Program of Activities (PoA) under the CDM

A suitable financing option to ease the extra burden from the feed-in tariff might be through the approval of wind power plants under the feed-in tariff as a Program of Activity (PoA) under the Clean Development Mechanism (CDM). The basic idea is that wind power plants remunerated through feed-in tariff will be automatically approved under the CDM allowing to gather Certified Emission Reductions (CER) for these plants. In essence through a wind power CDM PoA additional income would be generated by selling the CERs on the international carbon markets. Through this mechanism devel-

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oped nations will finance the expansion of renewable energy in developing countries like Vietnam. The additional income stream can be used in different ways which we will discuss later on. This is to be compared to the present situation where developers may submit individual projects for CDM approval.

Figure 12-2: Comparison of individual submission of projects under CDM (left) vs. submission as a Program of Activity (right). Registration of the wind power plants in Vietnam as a large scale PoA would result in several positive benefits for the country and further promote renewable energy developments. The CERs revenues from a PoA would offer the opportunity for Vietnam to cover its additional cost resulting from the feed-in tariff which is about to be implemented in the near future. Primarily the final electricity customers will be burdened with higher electricity prices resulting from the feed-in tariff. In case the revenues accrue to the single buyer of electricity (EVN) they could be used for additional measures to promote renewable energy. More-over, lower energy consumption costs for the final consumer may result and new incentives for potential independent power producers might be offered in terms of saving CDM transaction costs. Advantages of a PoA in contrast to conventional CDM projects are inter alia: A PoA can involve CPAs being run in multiple countries. New projects can be added to a PoA without restarting the validation process. No registration fee is payable on projects under the PoA which are added after validation. Only one approved baseline and monitoring methodology for all projects under the PoA is required. A PoA reduces transaction costs (CDM registration, validation, monitoring etc) for the project developers Discussions about Programs of Activities usually assume the aggregation of many small-scale activities which are not viable to run as individual CDM projects (such as the installation of energy efficient light bulbs in residential houses etc.). However, there is no technical restriction which prevents the creation of a PoA which includes as CPAs projects which would normally

Projects

PDD submission

UNFCCC

Income

Certificates

Carbon Markets

Projects

PDD submission

UNFCCC

Income

Certificates

Carbon Markets

Programme of Activity

Individual Activity Programme of Activity

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be registered as individual CDM projects (e.g. large scale projects like wind power plants). In fact, the UNFCCC Executive Board has clearly indicated that PoAs involving large-scale projects as CPAs are permitted by releasing versions of the Program of Activities Design Document and CDM Program Activity Design Document for both large-scale and small-scale projects (to be found on the UNFCCC website under Program of Activities PoA- Forms). In the following we will first discuss the requirements by the UNFCCC for submitting a PoA and some possible approaches how to submit wind power plants under the feed-in tariff as a PoA. Possible approaches of how to organize the PoA process in Vietnam are also outlined e.g. which institution can act as managing entity or best practice for CERs use etc. Since experi-ences with PoAs in general are very limited and no large scale projects have been submitted as PoA in particular the ultimate feasibility of such approach could be only proven when – after consultation with the state authorities, the UNFCCC and other stakeholders – a PoA for the feed-in tariff plants would be submitted. However, such an endeavor would put Vietnam on the forefront of innovative mechanisms to transfer monies from the developed world to the developing world on large scale. The Framework of Program of Activities In this section the fundamental basics of a CDM Program of Activity are outlined. According to the Executive Board a Program of Activity under the Clean Development Mechanism is defined as follows: “A Program of Activities (PoA) is a voluntary coordinated action by a private or public entity which coordinates and implements any pol-icy/measure or stated goal (i.e. incentive schemes and voluntary Programs), which leads to anthropogenic GHG emission reductions or net anthropo-genic greenhouse gas removals by sinks that are additional to any that would occur in the absence of the PoA, via an unlimited number of CPAs.” (UNFCCC07a) Project activities under a PoA can be registered as a single CDM project activity. A PoA is made up of CDM Program Activities (CPAs). Multiple CPAs can be included under a PoA at the time of registration and additional CPAs can be added at any point in the life of the PoA. A PoA is also entitled as Programmatic CDM. Programmatic CDM include so called CDM project bundling. Bundles are defined as the “Bringing together of several small-scale CDM project activities, to form a single CDM project activity or portfolio without the loss of distinctive characteristics of each project activity.” (UNFCCC05a) The envisaged PoA is an action, which coordinates and implements wind power under the feed-in tariff i.e. the policy. The implementation of the feed-in tariff leads to the reduction of anthropogenic GHG emissions. It is unclear at this point to which extent the participation of the wind power projects needs to be voluntary. That touches the questions whether one can

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oblige wind power plant operators benefiting from the tariff to join into the PoA. The UNFCCC has confirmed that large-scale projects are also eligible to be bundled. However a PoA is distinguished from CDM project bundling as shown in the following chart:

Program of

Activity Bundle

Sites Exact sites of project activities may not be known in advance

↔ Ex ante identification of exact sites.

Project activities

The sum of all individual activi-ties under the Program is the CDM project activity. At submission only targeted activities are identified, while actual activities are not confirmed until verification.

↔

Each activity in the bundle is an individual CDM project activity.

Project participants

Only the entity implementing the Program and not the individual project stake-holders represent the project activity as a CDM project participant

↔

Each single activity is represented by a CDM project participant.

Table 12-6: Comparison of Program of Activities vs. bundling individual projects. (DEHST07).

Currently (October 2009) one Program of Activity has been successfully registered with the UNFCCC so far and another has requested registration. These PoAs cover an efficient lighting scheme and the capture and combus-tion of methane from animal waste. Although the projects are of small scale dimension they can be seen as a guideline for large scale projects concern-ing the structure of the documents needed for registration. In the following section the most important principles for PoA related to the UNFCCC publications is discussed.

12.4.2.1 Requirements for a Program of Activities

12.4.2.1.1 The CDM PoA Lifecycle

A Program of Activities must be directed at coordinating and implementing a policy/measure or stated goal. No clear definition is provided for these

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terms. However, the Executive Board has explicitly referred to incentive schemes and voluntary Programs in its definition of a Program of Activities. In general, a PoA must demonstrate real, additional and measurable emis-sion reductions or removals attributable to the PoA: “The PoA shall demonstrate that net reductions in anthropogenic emissions or net anthropogenic greenhouse gas removals by sinks for each CPA under the PoA are real and measurable, are an accurate reflection of what has occurred within the project boundary, and are uniquely attributable to the PoA. The PoA shall therefore define at registration, the type of information which is to be provided for each CPA to ensure that leakage, additionality, establishment of the baseline, baseline emissions, eligibility and double counting are unambiguously defined for each CPA within the PoA”( UNFCCC07a) A coordinating/managing entity shall develop a Program of Activities Design Document (CDM-PoA-DD) setting a framework for the implemen-tation of the PoA and unambiguously defining a CDM Program activity (CPA) under the PoA. Further the coordinating/managing entity must prepare the PoA specific CDM Program Activity Design Document (CDM-CPA-DD) using the provisions of the proposed PoA. At the time of request-ing registration the CDM-POA-DD must be accompanied by a generic CDM-CPA-DD form that has been specified for the proposed PoA, as well as by one completed CDM-CPA-DD (using a real case). After the first CPA that is added over time to the PoA, each following CPA must submit a completed CDM-CPA-DD. Eventually the following documents are needed: For a PoA registration: A complete CDM-PoA-DD A PoA specific CDM-CPA-DD with generic information relevant to all CPAs (blueprint/template) A completed CDM-CPA-DD which is to be based on the application of the PoA to one real case For renewable of the crediting period of PoA: A new CDM-PoA-DD A new PoA specific CDM-CPA-DD For renewable of the crediting periode of CPA: CDM-PoA-DD ( to be compared with latest CDM-PoA-DD)

The role of the coordinating/managing entity The rules for creating a Program of Activities (PoA) introduce a new concept into the CDM system: the so called coordinating or managing entity. This entity is responsible for proposing and overseeing the PoA. A PoA shall be proposed by the coordinating or managing entity – the entity shall be a project participant authorized by all participating host country Designated National Authorities (DNAs) involved and identified in all correspondence as the entity which communicates with the Executive Board, including on matters relating to the distribution of CERs .

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There do not appear to be any restrictions on who can be a coordinating or managing entity beyond the requirement that they must be a project partici-pant. The coordinating/managing entity can be a public or private entity. If the participation should be of financial or organisational kind is not stated. The coordinating or managing entity has the task to check that none of the CDM Program Activities (CPAs) have been registered as individual project activities already. The entity shall identify measures to ensure that all CPAs under its PoA are neither registered as an individual CDM project activity nor included in another registered PoA and that the CPA is subscribed to the PoA. These measures are to be validated and verified by a Designated Operational Entity (DOE). In the so far registered or submitted PoA asking for registration or correc-tion the coordinating/managing entities are to mention but a few: Cool nrg Carbon Investments Pty Ltd, TSESL India (a subsidiary company of Thermax Limited) and JPMorgan Ventures Energy Corporation which are all private companies. Moreover there is also a public coordinat-ing/managing entity named Bureau of Energy Efficiency (BEE) which takes part in a CFL lightning scheme project in India. Project participants in a Program of Activities Entities involved in implementing the PoA and listed on the Program of Activities Design Document (CDM-POA-DD) are project participants. Project participants are simply registered in relation to the PoA, and need not be involved in any CDM Program Activity (CPA) within that PoA. Conversely, most of the entities involved in implementing an individual CPA will not be project participants in the PoA, and there is no requirement that they need to be project participants. This is only due to the coordinat-ing/managing entity. It is therefore possible for the coordinating or manag-ing entity to be the only Project Participant in the Program of Activities. There are no project participants registered for individual CPAs, although the entities responsible for the CPA are listed on the CDM-CPA-DD. As with CDM project activities, the Executive Board leaves the relationship between the coordinating/managing entity and any other project participants as a matter to be determined between themselves, usually through contract. Project participants will negotiate with the coordinating/managing entity in relation to communications with the Executive Board and distribution of CERs. Additionality In the context of a Program of Activities (PoA), the requirement of addi-tionality means that both the PoA itself and each CDM Program Activity (CPA) would not have been implemented, or would not have been imple-mented to the same extent, without registration under the CDM. Additional-ity must also be proven at the level of individual CPAs. The criteria for demonstration of additionality for each CPA must be outlined in both the Program of Activities Design Document (CDM-POA-DD) and the in the CPA Design Document (CDM-CPA-DD). Essentially, this is aimed at ensuring that each CPA will produce credible emission reductions or abatement. Evidence must be included within the PoA Design Document

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(CDM-POA-DD) to show that all CPAs will produce net greenhouse gas emissions reductions or sequestration. In the following years it might be challenging in Vietnam to prove that a wind power project would not have occurred without the CDM as the by then implemented feed-in tariff is meant to make it financially attractive anyway. The CDM project managers may find it difficult to prove that they cannot get funding for the project from elsewhere. Whether the CDM executive board accepts the submitted CDM-PoA-PDD depends primarily on how the additionality of the project is shown. However, the UNFCCC has stated that perverse incentives should be avoided and that means all CDM projects are still additional as the feed-in tariff should be disregarded from the baseline. This applies only to policies implemented after 2001 (UNFCCC04A). Therefore it can be assumed that additionality for a large scale wind power PoA in Vietnam can be proven similar to CDM projects which generate electricity from renewables and taking place in countries without feed-in law. Subsidies from the feed in tariff, the avoided cost tariff or most of the other subsidies granted by the Vietnam Environment Protection Fund would be disregarded as most of these policies are implemented after 2001. In relation to assessing additionality for a PoA, the coordinating/managing entity must demonstrate that in the absence of the PoA: (1) The proposed voluntary measure would not be implemented, or (2) the mandatory policy/regulation would be systematically not enforced and that noncompliance with those requirements is widespread in the country, or (3) that the PoA will lead to a greater level of enforcement of the existing mandatory policy/regulation. This shall constitute the demonstration of additionality of the PoA as a whole. (UNFCCC07e) In the case of a wind power PoA in Vietnam option 3 suits best to show the additionality of the PoA. As the feed-in law can be considered as the existing regulation it must be proven that the PoA will lead to a greater enforcement of the policy. The more wind power plants are implemented the greater is the enforcement of the feed-in tariff. Additionally, also (1) may apply as the installation of wind power plants can be regarded as voluntary measure which would not be implemented without the PoA. If one takes this path however revenues from CER marketing need to be used for promoting the respective wind power plants. As the wind power plants in Vietnam will deliver renewable energy to the national electricity grid the consolidated methodology for grid-connected electricity generation from renewable sources AMC0002 Version 10 applies to demonstrate the additionality of the PoA. According to the AMC0002 methodology the additionality of the project activity shall be demonstrated and assessed using the latest version of the tool for the demonstration and assessment of additionality agreed by the CDM Executive Board. Hereafter additionality must be proven through four steps as presented in Table 12-7. If the project passes all steps shown above it is considered as additional.

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Step Procedure SR Vietnam 1.)Identification of alternatives

Identification of alternatives tothe project activity consistent with mandatory laws and regulations

Range of plausible technologies can be considered as alternative. Examples of such technologies in Vietnam include gas-fired plants, hydro power etc.

2.)Investment analysis (Note: project partici-pants can choose between step 1 or step 2 or do both)

Determination of whether the proposed project activity is economically or finan-cially less attractive than other alternatives without the revenue from sale of certified emission reduction.

The project internal rate of return (IRR) can be used as financial indicator to assess a wind power project

3.)Barrier analysis (1) Is there at least one barrier preventing the implementation of the proposed project activity without the CDM, and (2) Is at least one alternative scenario, other than proposed CDM project activity, not prevented by any of the identified barriers?

First o its kind: no grid connected wind farm has been commissioned so far Technology and technical Capacity: Wind power technology has to be imported No skilled Workforce and operational Risk Policy and Law: Legislation relating to renewable energy and wind power is still in its infancy Energy Industry Framework: Sector is in change (implementation of a competitive energy sector according to energy law 2004)

4.) Common practice analysis

(1) No similar activities can be observed? (2) If similar activities are observed, are there essential distinctions between the proposed CDM project activity and similar activities that can be explained reasonably?

Here (1) would be applied as no similar activities are existing in Vietnam

Table 12-7: Required steps to prove additionality. Regarding Vietnam as a whole, wind power may fulfill the additionality criteria. Wind power generation mainly competes with oil fired plants and hydro plants which generate at low costs due to the favorable conditions of the domestic production. The government of Vietnam has introduced a law for CDM projects to provide “...preferential treatment: regarding tax, land use fee, land lease fee, deprecation of fixed assets; investment credit of State stipulated in this Decision... Entitled to be under consideration of enjoying subsidy policy to products of the CDM project... ” (DEC07b) Through the provision of this law the project developers are granted priority over non CDM projects. As part of this Decision, PoA developers can apply for a government subsidy tariff for wind power produced by wind power projects at a premium above the EVN purchase price. Without registration as a CDM project, the PoA developers would not receive the preferential treatment outlined in Decision No.: 130/2007/QĐ-TTg, and hence would probably not implement a wind power PoA.

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Duration For non forestry projects the duration for a PoA is 28 years and 60 years for a PoA forestry project. The baseline has to be checked every 7 years and changes apply to all CPAs at first renewal. As CPAs can be added through-out the PoA lifetime, the crediting period for CPAs which are added in year 25 of the PoA will end with the PoA. (WB09). Baseline When it comes to the approval of the CDM PoA another crucial point is the determination of the baseline. A baseline is a hypothetical reference case, representing the volume of greenhouse gases that would have been emitted if a Program of Activities (PoA) or CDM Program Activity (CPA) had not been implemented. A baseline must be established for the PoA and all CPAs within the PoA. The Program of Activities Design Document (CDM-PoA-DD) (and corresponding design documents for other PoA types) must include a justification of the choice of an approved baseline methodology and an application of this methodology to determine the baseline. For grid-connected renewable energies like wind power plants the approved consolidated methodology ACM0002 determines that renewable energy projects connected to an electricity grid are reducing CO2 emissions in an electricity grid by displacing electricity which otherwise would have been generated by grid-connected fossil fuel power plants and by the addition of new generation sources. Thus, baseline emissions include only CO2 emis-sions from electricity generation in fossil fuel fired power plants that are displaced due to the project activity. The baseline emissions are calculated by multiplying the displaced electricity generation of connected fossil fuel power plants, which is equal to the electricity generation of the project activity, by the CO2 emission factor of the electricity system. The grid emission factor is calculated according to the Tool to calculate the emission factor for an electricity system and determines how much CO2 emissions are released into the atmosphere by a given electrical grid to produce 1 MWhel. BEy = EG pjy *EF grid,CM,y Where BEy = Baseline emissions in year y (tCO2/yr) EGPJ,y= Quantity of net electricity generation that is produced and fed into the grid as a result of the implementation of the CDM project activity in year y (tCO2/yr) EFgrid,CM,y= Combined margin CO2 emission factor of the electricity grid in year y (tCO2/yr) The baseline and the emission reduction of a PoA changes constantly and has to be renewed after implementing new plants. There are several con-ceivable options for a sampling method. Yet there is no indication given by the Board of how to include new plants in an existing PoA. Therefore different possibilities are conceivable as shown below:

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Bundle plants according to the vintage. Bundle plants according to their area they are implemented in.(spatial principle) Calculation of Emission Reduction Every project activity eligible under the CDM will lead to long-term emission reductions. The emission reduction of a project activity is related to a baseline which reflects the emissions that would occur in the absence of the project activity. The emission reduction depends further on the type of project and its calculation is depicted in each methodology. The amount of the emission reduction of the project activity is fully credited in the form of CERs. The amount of reduced emissions and consequently of CERs granted is based on the baseline scenario and on the project and leakage emissions. The difference between the baseline emissions and the project and leakage emissions is the project emission reduction. For grid-connected renewable power plants the following applies ERY = BEy - PEy - LEy where ERy = Emission reduction in year y (tCO2/yr) BEy = Baseline emissions in year y (tCO2/yr) PEy = Project emissions in year y (tCO2/yr) LEy = Leakage emissions in year y (tCO2/yr) As there are neither leakage and nor project emissions for a large scale wind power project under a CDM PoA it is easy to calculate the baseline and the emission reduction. However the fact that under a PoA additional CPAs can be added at any point in the life of the PoA makes the situation more complicated. Candidates for Managing/Coordinating entities In the following we will review alternative options for what institutions would be feasible to take over the task of the managing/coordinating entity for a PoA in Vietnam. Since the suitability of institutions is very much linked with the question how the Certified Emission Reductions (CER) are handled and how the additional income from CER should be used we will discuss these two issues in parallel. As there do not appear to be any UNFCCC restrictions on who can be a coordinating/managing entity beyond the requirement that they must be a project participant several scenarios are conceivable. The entity being responsible for the PoA might be based on governmental level. Here three different options come under consideration: national, provincial or local level. On the national level, the Vietnam Environmental Protection Fund, the Renewable Energy Development Office (REDO), the Renewable Energy Development Fund (REDF) or the EVN would be assigned. Vietnam is divided into 58 provinces. There are also 5 centrally-controlled municipalities existing at the same level as provinces. The provinces are

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divided into districts, provincial cities and towns, which are subdivided into towns or communes. The centrally-controlled municipalities are divided into rural districts and urban districts which are subdivided into wards (DGV20). Vietnamese provinces are controlled by a People's Council, elected by the inhabitants. The People's Council appoints a People's Committee, which acts as the executive arm of the provincial government. Provincial govern-ments are expected to be subordinate to the central government (CSA96). For the purpose of the feed-in tariff for renewable energies it is likely that the national government will commission EVN to function as single buyer of electricity. To reach the goals set by the renewable energy action plan, the national development strategy and the masterplans it is required that all levels of government work together. The Vietnam Environment Protection Fund Initial situation: the national government function as managing / coordinat-ing entity (The Vietnam Environment Protection Fund (VEPF)) The VEPF is functioned to mobilize capital from the state budget, funding sources, contributions, entrusted fund from organizations and individuals at home and abroad, aiming at providing financial support for environmental protection activities nationwide. VEPF is under the administration of the Ministry of Natural Resources and environment (MONRE) and under the financial management of the Ministry of Finance (MOF). VEPF operates for non-profit purposes. Among many other functions the VEPF is responsible to organize registra-tion, monitoring and management of CERs to organize registration of receiving, dividing and selling CERs with CER owners or CER receivers; to collect CER sale charges to cover expenses of charges collection; to spend on support of dissemination and propaganda operations of Clean Develop-ment; to establish, set up, appraise and approve investment project docu-ments in compliance with Clean Development Mechanism to manage and monitor implementation of CDM project and other CDM concerned pur-poses in compliance with the law, conducting price support for products of CDM project as stipulated by the law.

Pro Contra Skilled personnel with experience in the CDM sector

No direct contractual relation with the power plant operators

Financial resources as funded by the state

In addition to the CER fee concept

Accounting of CER fees Project participation exists through price support for CDM products and subsidy electricity tariff

Provincial Government Initial situation: the provincial government function as managing / coordi-nating entity on regional level (currently no entity existing)

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Alternatively to the national management PoA can also be managed on provincial level. For instance the Department of Resources and Environment or similar departments in charge of environment topics exist in every province. This alternative should not be investigated as administer PoAs in every of the 58 provinces would further create a lot of transaction costs. Therefore a far less complicated way would be to assign institutions which are responsible for the PoA in each of the eight regions of Vietnam. There is no governmental institution implemented at the moment to overtake the managing task. However it is conceivable to choose eight provincial de-partments as managing entities and extend their sphere of influence to regional level.

Pro Contra Especially in the long term when renewable projects are widely spread over the country managing entities on provincial level might be useful

Breaking down the nationwide targeted amount of some 1000 MW of wind power on the regional level would leave only small PoAs left. Therefore region wide PoA management would mean a lot of effort.

Provincial departments with energy and environmental background already exist in the provinces therefore no new entity would have to be implemented

Currently no entity exist. Unclear if provincial depart-ments can overtake management for projects which are not implemented in their province. Bears the danger of conflicts of interest.

Many provinces are not aware of Climate Change issues in particular CDM. Lack of information, tools and experiences in this field.

Electricity of Vietnam (EVN) Initial situation: the national government function as managing / coordinat-ing entity (Electricity of Vietnam (EVN)) EVN is a state-owned company under the Ministry of Industry and Trade (MOIT). EVN operates in the areas of production (78%), transmission (100%), distribution (95%) and sales of electricity power with the charter capital of over 48 thousand billion Vietnam dongs (approximately $3 billion). EVN has 7 power companies and 5 consulting entities (including the Institute of Energy), 9 thermo and hydroelectric plants, 5 transmission entities, 2 companies producing power equipment and 3 power vocational schools. EVN Telecom is also an independent member of the corporation. According to the electricity law released in 2004 EVN is in the 1st phase of the restructure process changing the energy sector to a competitive whole-sale market by 2022 and finally to a complete retail market by 2022. EVN will change from single buyer to a shareholding in a competitive sector

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Pro Contra Financial project participa-tion exists in form of the avoided tariff. Moreover the feed-in tariff would also mean participation

Shifts more power towards EVN. Contradiction to the electricity law 2004 which favors a competitive market

At the moment it function as single buyer of electricity produced by IPP and has therefore good knowledge of the energy sector

In the long term EVN will be restructured into a shareholding (according to the electricity law 2004). How will PoA revenues be distributed then? Probably not possible to cover Refit.

EVN and its subsidiaries are deeply involved into other main functions regarding the power sector

The Renewable Energy Development Office Initial situation: The Renewable Energy Development Office (REDO) function as managing / coordinating entity In its master plan the Vietnamese government proposed the implementation of a new entity called REDO. According to the master plan the Renewable Energy Development Office will be established as an independent organiza-tion, whose activities are as follows: As national focal organisation promotion of renewable energy development, particularly for off-grid and household-level power development Governmental representation in international organisations on RE: Set standards, initiate investment preparation studies for emerging renew-able energy technologies and encouraging development of domestic tech-nology development where appropriate. Prepare plans for renewable energy development as the basis for setting the size of the RE electricity levy level. Prepare prospectuses for opportunities to invest in Renewable Energy projects and assist developers in obtaining the necessary permits, applying for carbon finance and application for support from the renewable Energy Fund. Developing and managing Feed-in Tariffs for RE projects.

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Pro Contra Independence, less affected by the government

The institution does not exist yet

Consisting of representatives from related governmental ministries

REDO should promote, assist and facilitate the efforts of developers for grid-connected projects, and of communi-ties and local entities for off-grid schemes, but should not itself run the competitive processes for disbursement of subsidies.

Foreseen as implementing institution of the feed-in tariff, therefore a good overview over subsidy, revenue and tax fluxes is given as well as knowledge about existing and potential RE projects through a proposed RE database

The main focus is on renewable energy promotion particularly on off-grid and household-level.

Secure governmental Funding trough a budget allocation from the proposed Renewable Energy Devel-opment Fund

Through a fundamental and planned development of this institution and its human resources the convenient option arises to embed and cultivate bespoken skills and capabilities among its personnel from the first minute

Renewable Energy Development Fund Initial situation: a private entity function as managing / coordinating entity (Renewable Energy Development Fund (REDF)) In addition to the REDO the master plan also considers to establish the REDF. The key function of REDF will be to disburse the following support subsidy for RE projects: • Subsidy to grid-connected RE projects. • Subsidy to off-grid RE electrification projects (initial capital investment

as well as tariff support and for O&M). • Subsidy to end-users (e.g. for PV systems, biogas systems, solar water

heaters, ICSs). • Subsidy for studies, R&D, renewable energy database development. REDF’s principal function is to disburse financial support for renewable energy development in an equitable and transparent manner. Its operating rules have to be separated from any vested interests (just as the system operator in the competitive generation market, operates as an independent not affected by any generators and consumers, but playing the role to ensure the least cost operation and system reliability). To be effective, the REDF must have a predictable and secure funding base, so that lenders see subsidy commitments as credible. The level of funding must also be sufficient to enable the RE development targets to be met.

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Conclusion As shown in the table below we consider the EVN and Renewable Energy Development Office (REDO) as best suited entities to manage the PoA. We rank EVN preliminary to REDO since they are operational. Moreover, EVN as the single buyer of electricity has direct connection to the power produc-ers. With the REDO being the future focal point for renewable energy development in Vietnam, REDO has very good prospects for serving as a managing entity in the future.

Candidate/ Aspect

Vietnam Environment

Protection Fund (VEPF)

Regional entity (provincial

departments like Department of Resources and Environment)

Electricity of Vietnam (EVN)

Renewable Energy Development

Office (REDO)

Renewable Energy Development Fund

(REDF)

Qualified staff / personal resources ● ● ●

National government acceptance ● ● ●

UNFCCC acceptance ● ● ● Restructuring/ implementation process

● ● ● ●

Knowledge of the RE-sector ● ● ●

CDM experiences ● ● ● ●

Sphere of influence ● ●

Future prospect ● ● ●

Possibility to cover the feed-in tariff ● ● ● ● Ranking 3 4 1 2 5

Table 12-8: Assessment of different institutions on the feasibility as managing entity for a Program of Activity. Note: ● poor ● good

Pro Contra Project participation guaranteed through subsidies.

Not clear who will be stakeholder

Specialised on subsidies, can entity participate in project organization? Enough personnel resources?

Overlapping and control difficulties with Vietnam Environment Protection Fund

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Usage of PoA Revenues Two alternative scenarios for the Socialist Republic of Vietnam as manag-ing entity for PoA are conceivable when it comes to the use of the revenues: Either financing projects in different business fields or in the energy sector only. There are no guidelines published by the UNFCCC indicating ways of how to use the CERs revenues. Outside the energy sector, a national account for the earnings of the PoA CERs could be founded. A suitable usage for the money would be national projects (topics: fighting poverty, improving infrastructure, subsidies for the domestic agriculture sector etc.) or moreover environmental projects to get the link between different parts of the sustainable development within the country (social, economic and environmental aspects). Within the energy sector, the revenues of the PoA could be used to reduce the burden from the feed-in tariff on power customers as with the revenues the extra costs resulting from the tariff could be covered to some extend. This would help the Communist Party of Vietnam (CPC) to strengthen its support among the population. The party’s assertions on sustainably devel-opment in Vietnam (inter alia in the master plans) put the emphasis is on supporting cost-effective technology which increases sustainable jobs and improvement of the energy situation in Vietnam. The conduction of PoAs and using the revenues out of it to lower the electricity costs would lead to credibility with the citizens. Low electricity price means tackling poverty. Alternatively, the revenues could be used to support additional new wind power plants to extend the existing wind farms. Through adding new CPAs to the PoA the CERs income would increase. Otherwise, the revenues could be used to provide the support for the plants (maintenance and repair, add new technique) which generated the CERs. Finally, the revenues could be used to finance supporting means for wind power development e.g. provid-ing soft loans, grid planning, wind resource assessment, establishing natural standards. Only the entity implementing the PoA and not the individual project stake-holders represents the project activity as a CDM project participant. Project stakeholders therefore won’t have direct access to the CERs and depend on the managing entity.

12.4.2.2 International Acknowledgement of large scale PoAs under the CDM

Different stakeholders in international climate change negotiations have already expressed their views on Program of Activities. This is important to know to assess the sustainability of such an approach on the medium and long run.

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United Nations As shown the UN published the necessary framework for the implementa-tion of large scale PoAs under the CDM and indicates a raw guideline but leave the final implementation to the project developers.

China China wants to encourage the domestic wind power industry. The govern-ment has issued a regulation stipulating that 70 percent of wind power equipment should be produced from domestic companies regardless of the source of funding. The Chinese government appears keen to synchronize growth with the development of its own domestic renewable industry. Many CDM projects already taking place in the People’s Republic of China. For instance, virtually all Chinese wind power plants so far have benefited from CDM. The generated CERs have to be sold via one central national institu-tion. If no foreign buyer is determined by the time a project is submitted for approval the emission reductions generated by the project will be transferred into China’s national account in the CDM registry and can only be trans-ferred out with the authorization of China’s Designated National Authority for CDM. Further the Chinese government charge fees for the CERs which are used in supporting activities on climate change Hence the frameworks already correspond to the idea of the PoA. It can be assumed that China will have an open minded attitude towards PoAs ideas but always with the ulterior motive to boost its national production, and putting its interests ahead of other countries (DOCC05).

Greenpeace Greenpeace proposed a feed-in tariff system in developing countries fi-nanced by emissions trading from OECD countries. It is called Feed in Tariff Fund Emissions Trading model (FFET), a concept conceived by Greenpeace International. The aim is on the expansion of renewable energy in developing countries with financial support from industrialized nations. In a nutshell it should link the feed-in tariff system with emissions trading schemes such as in Europe through already established international funding channels. FFET concept consists of three elements – fixed feed-in tariffs, emissions trading and a funding arrangement. The FFET fund will act as a buffer between fluctuating CO2 emission prices and stable long term feed-in tariffs. The fund will secure the payment of the required feed-in tariffs during the whole period (about 20 years) for each project. This fund could be managed by international financial institutions operating in Europe and Central Asia or by Multilateral Development Banks. Comparing the FFET model with the concept of covering the REFIT costs through a PoA it becomes clear that the basic idea is similar - expan-sion of renewable energy in developing countries with financial support from industrialized nations. However the FFET model considers funding from an international Fund whereas the PoA model aims on financial support from national managing entities.

WWF The WWF is very concerned that the whole CDM system is being misused. For instance many projects being developed do not fulfill the additionality criteria. That means that a lot of these projects would have been realized even without the CDM financial support. If these CERs attaining the

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European emission trading system it will lead to a global rise of emissions (ÖI07).

12.4.2.3 Conclusion on Program of Activities

It is a viable option to submit wind power plants under the planned Feed-In regulation as a Program of Activity (PoA) within the CDM framework. The revenues generated through the marketing of Certified Emission Reduction (CER) can substantially ease the extra burden to the Vietnamese power consumers. At the same time, transaction costs are lowered so that more of the CER revenues are available for the deployment of wind power in Vietnam. Experiences with PoAs are still very limited. Moreover, PoAs have origi-nally been designed for small scale applications, so that the application on wind power would be first of its kind. Also, the connection of a PoA with a feed-in regulation has not been applied so far. However, our analysis of the framework for PoA shows that wind power under a national feed-in regula-tion is in general feasible as a PoA. In international climate negotiations there is a move away from pure project based measures towards more sectoral targets and programmatic approaches where a PoA based on a feed-in tariff would ideally fit in. So we regard the prospects for a PoA on wind power under a feed-in regulation as very good. The ultimate feasibility of such approach could be only proven when a PoA for the feed-in tariff plants would be submitted to the UNFCCC. Such an endeavor would put Vietnam on the forefront of innovative mechanisms to transfer monies from the developed world to the developing world on large scale. In a next step, the development of the relevant designed documents for submission to the UNFCCC needs to be developed. Thereby, the follow-ing crucial issues need to be addressed: • Ownership of CER; • Use of revenues; • Definition of wind power plants under the PoA; • Participation on a default basis or voluntarily. These issues should be solved with the participation of all relevant stake-holders as shown in the following table.

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Stakeholder Performance Resources Connections Ministry of Natural Resources and Environment (MONRE)

issuance of electricity law 2004, administra-tion of the Vietnam Environment Fund

information, political significance

Function as overall coordinator, therefore connections to all other players

Ministry of Industry and Trade (MOIT)

regulates industry, developed master plans, developed power sector guidelines

organisational and political significance

EVN, Electricity Regulator of Vietnam

Ministry of Finance (MoF)

In charge for the financial management of the Vietnam Environment Protection Fund

organisational Vietnam Environment Protection Fund

Ministry of Planning and Investment

stakeholder of the Vietnam Environment Fund

Electricity of Vietnam (EVN)

REAP, single buyer of electricity, performing in generation, transmission and distribution

political significance MONRE, eight subsidiary companies of EVN, MOIT

Electricity Regulatory Authority of Vietnam

announced the avoided cost tariff, regulation of the energy market, licensing

financial resources, consulting

MOIT

National Assembly most important national governmental organ

political power all political entities

World Bank brought about the REAP

financial resources, consulting

investors, MONRE

Vietnam Environment Fund

offers price subsidies to CDM investors, subsidises electricity tariff, clollects CER fees

financial resources, informational resources, personal resources

State Bank Vietnam, Electricity Regulator of Vietnam, MoF

State Bank of Vietnam financing the Vietnam Environment Fund and some renewable projects

financial resources Vietnam Environment Fund

Department of Meteorology, Hydrology & Climate Change (DNA)

Designated National Authority, approval of CDM projects

informational resources

MONRE

Independent Power Producers

PPA with EVN, invest in former EVN owned plants

EVN

Renewable Energy Development Office (REDO)

promotion, preparation and standard setting for renewable projects

organisational and personal resources

REDF, different governmental institutions through assigned representatives

Renewable Energy Development Fund (REDF)

support of CDM project investors

financial resources stakeholders, project developers, REDO

Institute of Energy (IoE)

driving force of the six master plans, formulating

(MONRE)

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12.4.3 Developments of a Post 2012 CDM

Various activities are underway to rethink the practicability and efficiency of the CDM. The upcoming Copenhagen Climate Change Negotiations in December 2009 expect a couple of new decisions on • the overall framework of CDM and • on the procedures, and its governance. The continuation of the CDM will be embedded into the overall climate negotiations trying to fix a new treaty Post 2012. The Kyoto Protocol in its Article 9 states that COP/MOP shall "… periodi-cally review this Protocol in the light of the best available scientific infor-mation and assessments on climate change and its impacts, as well as relevant technical, social and economic information…". The following related documents were available at the time of writing the report and were reviewed: • Review of the Kyoto Protocol pursuant to its Article 9. Submissions from

Parties, 8 September 2006 including a contribution by Finland on behalf of the European Community and its member States, submission received 31 July 2006;

• Decision 2/CMP.4 "Further guidance relating to the clean development mechanism, CMP 4 dated 1 to 12 December 2008; Poznan

• Proposal by the "The Ad hoc working group on future commitments for Annex I Parties under the Kyoto Protocol", 12 March 2009;

• Call for inputs on efficiency in the operation of the CDM and opportuni-ties for improvement the future CDM, initiated by CDM EB and UNFCCC secretariat, open between 30 March to 4 May 2009

• A Proposal for a Copenhagen Agreement by Members of the NGO Community; 8 June 2009

• DIRECTIVE 2009/29/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL of 23 April 2009 amending Directive 2003/87/EC so as to improve and extend the greenhouse gas emission allowance trading scheme of the Community

12.4.3.1 Review of the Kyoto Protocol, EU contribution, September 2006

The EU is convinced that in the future, the flexible mechanisms could become a stronger instrument to change investment decisions in key sectors. There is potential for enhancing the Protocol on this and other aspects. The review covers all the provisions of the Kyoto Protocol, including its deci-sions. Apart from amendments to the Kyoto Protocol that will be technically necessary in order to adapt it to a second commitment period after 2012, items that might need to be addressed in the review include, inter alia:

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• The scope and effectiveness of the flexible mechanisms, in particular the clean development mechanism;

• Possible changes to Annex A (sectors, sources); • The treatment of land use, land use change and forestry; • The possible inclusion of bunker fuels in the Protocol.

12.4.3.2 Decision 2/CMP.4 relating to the CDM, December 2008

Decision 2/CMP.4 provides a substantial list of decisions related to the CDM and therefore gives some initial insight into how the entire mechanism is likely to develop. In specific, the decision refers to: • Governance of the CDM • Accreditation of DOEs • Methodologies and additionality • Regional and sub-regional distribution and capacity-building, and • Resources It is obvious that the current operation of the system and its governance is not ideal and considerable efforts are needed to bring the CDM EB as the governing body back on track to rather focus on it executive and supervi-sory role and not as much on a project-by-project consideration as currently the case. Regarding the longer term governance of the CDM, the CDM-EB is re-quested to: • take actions that emphasize its executing and supervisory role; • keep the management plan under review and make adjustments to it as to

continue ensuring cost-effective, transparent and consistent functioning of the CDM;

• establish timelines for each of its procedures; • further improve transparency and consistency in its decision-making

process; • adhere to the principle that any decision, guidance, tool and rule shall not

be applied retroactively; • regularly update the CDM Validation and Verification Manual; • continue streamline the registration and issuance process; • enhance the effectiveness with communication of project participants;

and • closely monitor the adequacy of the operation of its support structure. Methodologies and additionality of project activities are revolving themes that needs continuous improvement. The CDM EB is requested among many other issues to • continue broadening the application of methodologies

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• further developing generic and user-friendly methodological tools • intensify work related to energy efficiency and renewable energy activi-

ties as CDM project activities • analysis the many approved methodologies not used • further improve the objectivity of approaches used to assist the demon-

stration of additionality and the determination of the baseline The CDM EB is requested to make recommendations to the CoP/CMP at its next session (Copenhagen, December 2009) for improving the efficiency of the operation of the CDM. In order to be able to address all these issues, the Board has opened a public call for inputs on improvement of the efficiency of the CDM (see summary further below). Decision 2/CPM.4 does give some insight into how the CDM will have to develop.

12.4.3.3 Proposal by the Ad-hoc working group, March 2009

The Ad-hoc working group on future commitments for Annex I Parties under the Kyoto Protocol has formulated some "Further elaboration of possible improvements to emissions trading and the project based-mechanisms", see FCCC/KP/AWG/2009/INF.2 dated 12 March 2009. The chapter on the CDM makes the following references and outlines • options for inclusion of other land use, land-use change and forestry

activities and outlines several modalities and procedures; • options on how carbon dioxide capture and storage could be included; • options regarding the acceptance of nuclear activities under the CDM,

and • options for introducing sectoral CDM for emission reductions below a

baseline defined at sectoral level.

The first three issues have no relevance and consequences for renewable energy projects while the last issue, sectoral CDM, may have an implica-tion.

Two options as how the sectoral CDM could be established are currently stated in the AWG report: • Option 1: "The baseline for a sectoral CDM project activity shall be the

scenario that reasonably represents the anthropogenic emissions by sources of GHGs within the sector boundary, …., that would occur in the absence of the project activity."

• Option 2: "The baseline shall be the carbon intensity [within the sector

boundary during the calendar year 2012] [defined by an appropriate benchmark established on the basis of each sector in each host country]."

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It is further proposed that the CMP (Conferences of the Parties serving as the meeting of the Parties to the Kyoto Protocol) is to adopt modalities and procedures for

• the determination of the sector boundary • the determination of additionality for sectoral CDM project activities • the determination of sectoral baselines, in particular through the use of

standardized baselines • the monitoring, verification and certification of emissions, and of emis-

sion reductions and removals, within the sector boundary.

In case the international community will follow this proposal consequences for any renewable energy project activity under the CDM can be expected as regards the overall framework of quantifying emission reductions. There will be an impact on the number of CERs a project can trade and monetize.

12.4.3.4 Call for public inputs on efficiency of the CDM, May 2009

In response to decision 2/CMP.4 the CDM-EB initiated a public call for inputs on the operation of the CDM and opportunities for improvement of the future CDM. A total of 42 public inputs from individuals, organizations and DNAs (Designated National Authorities) were submitted and are publicly avail-able. The public call resulted in a wide variety of subjects that are suggested to improve and that relate to the current operation of the CDM applying the modalities, procedures, methodologies, decisions and guidance as are currently in place. Only very few contributions state that the CDM making good efforts and would not require a large reform but just some consolida-tion of existing rules. The majority of public input, however, voice very clearly issues that would go beyond smaller adjustments but would require a substantial change in: • How the CDM operates, and • How the CDM is organized and setup. In the following major issues for improvement/reform of the CDM as regards the operation are summarized:

• There is an unbalanced regional distribution of CDM projects. Special

attention and provisions should be provided to foster CDM project de-velopments in currently underrepresented countries.

• Assess additionality through the development of positive lists of project activity types

• To bring performance of the DOEs in line with regulatory require-ments and thus phasing out the RIT (Registration and Issuance Team). This type of micro-management has never been intended by the Marra-kech Accords, which grant the right to project reviews in cases of sus-pected corruption or incompetence of the DOE. The project specific

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review should rather be replaced with a stringent and efficient accredita-tion and continuous assessment process resulting in well trained DOEs. The relationship between EB and DOEs has to be improved as it is cur-rently suboptimal. It was suggested to establish as a body of case law based on precedents.

• To provide greater clarity on the demonstration of financial addition-

ality. The EB is encouraged to seek out financial experts to assist them in its task of overseeing financial additionality to ensure that the CDM guidance is consistent with that of standard corporate finance theory and practice. It is further suggested to consider further training for Secretariat staff as well as the DOEs to ensure assessment and interpretation of fi-nancial analyses are conducted in a uniform and predictable manner and to the EB’s standards.

• Additionality should be defined by provenance and nature of emis-sion reduction not on a case by case basis. One of the main constraints around CDM projects comes from the way in which additionality has been defined. The system has to evolve from the current use of project additionality, to an emission reduction additionality approach. For exam-ple, transparently established, reliable benchmarks, set below business as usual scenarios for specific sectors, could be tailored to meet the chosen level of environmental protection, ensuring that an optimal bal-ance is struck between environmental integrity and ease of project ap-proval. The EB should encourage the development of dynamic baselines for specific methodologies, allowing baselines to be adjusted according to the ongoing level of technology penetration in a specific sector / coun-try.

• Enhance, stimulate and consolidate A/R project activities. Instead of include new LULUCF activities in CDM it is more important to consoli-date the A/R activities under the existing rules that were developed in order to guarantee the environmental integrity of Kyoto Protocol. Unless transaction costs are reduced, it is unlikely that the A/R activities will contribute to the mitigation of climate change. This is the more relevant barrier to be removed in order to develop A/R project activities under CDM.

• Enhance, stimulate and consolidate Program of Activities (PoAs). Instead of include sectoral crediting of emission reductions in CDM it is more important to consolidate PoA under the existing rules. Efforts are needed to develop institutional and technical capacity of national gov-ernments and private sector to formulate and carry out PoAs.

• Filling the critical gaps in the guidance:

i. Operationalising CDM Program of Activities (PoAs) ii. Incorporating the concept of materiality into CDM processes (e.g.

adopting a more business-friendly approach, for example by means of a bottom-up positive list of design changes that can be scrutinized and “acknowledged” by the verifying DOE.

iii. Defining an acceptable level of assurance iv. Providing Methodology Tools

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• To use clearer definitions and sentences in the guidance as well as in the methodologies. Guidance provided in the methodologies/tools by the Panels/ Working Groups/ EB sometimes does not fit the reality of project implementation which requires project participants to spend time and effort on clarifications, deviations, and incorporating additional guidance. This causes more time and cost for project implementation and less bene-fit is obtained from the CDM. To avoid these situation inputs from those who are experts in real project implementation should be involved and not only those from academia.

• Keep a roster of industrial and project financing specialists from developed and developing countries to be called upon for ad-hoc consul-tancy services to aid the official support structure (panels and working groups). In particular, it is strongly recommended to have project financ-ing specialists to take into consideration the actual practice in project financing and investment analysis for similar projects presented as CDM project activities. For transparency, their inputs should be publicly avail-able.

• To allow the EB, its panels, other outside expertise or the secretariat to define the default unit price of CERs to be used in calculating and comparing IRRs in the investment analysis, which will be updated regularly and made publicly available.

• To allow the DNAs in the host country to define the default values for "appropriate benchmarks" used in calculating and comparing IRRs in the investment analysis, which will be updated regularly and made pub-licly available.

Major improvements and/or changes to the organizational set up include: • Efficiency of the decision making process needs to be improved. The

supervisory role of the CDM EB has to be enhanced and the CDM bod-ies' decision-making processes be streamlined.

• To respect and implement common practice as in most legal systems to enact regulation regarding retroactive application of new guidance. Projects should be validated solely against applicable methodologies and guidance that were available by the time the project was posted for the 30-day public commenting period. Appropriate „grace periods" should be introduced and respected for any decision of the EB, and not only for methodologies and tools.

• To improve communication between EB and project developers. The EB does not clearly state the rationale for decisions on registration and issuance. Project developers should have a right to be heard before any final decisions on the project are taken. A well substantiated and clear explanation should be provided by the EB for any decisions taken.

• Limiting the time until an issue has to be resolved to a maximum of two consecutive sessions (of EB meetings).

• COP/MOP should establish an appeal mechanism which gives standing to individuals that are granted rights and obligations under the CDM and guarantees a full review of EB decisions. Project proponents, DOEs and

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anyone who is materially affected by the decisions of the EB should be able to register an appeal

• Establish separate committees on political and technical issues • Full time employment of EB members as opposed to part-time dedica-

tion • A rather technical background and practical project experience of EB

members should be required as to formulate rules and guidance that can be understood unambiguously by project proponents and users of ap-proved methodologies

• Indexing and publishing of decisions, legal value of precedent deci-sions and right to a second hearing (e.g. design and implementation of an appeal process for those projects that were rejected by the EB).

• Host countries must improve their domestic CDM organization (includ-ing project identification and overall DNA supervision).

• In addition to currently established types of calls by CDM EB on 1) call for comments prior to introduction of a new guidance/procedures, etc., and 2) a call for comments on a draft document before finalization for EB approval additional calls could be introduced to better integrate the public, e.g. 3) a call for comments post-decision/-introduction of new guidance/procedures, etc., and 4) a non-binding, quick call for comments on recommendations and draft methodologies, guidance, guidelines, tools, etc. resulting from MP, SSC WG, AR WG meetings prior to the subsequent EB meeting.

12.4.3.5 Proposal for a Copenhagen Agreement by Members of the NGO Community, June 2009

Members of the NGO community have drafted a Proposal for a Post 2012 Treaty on climate change. Such treaty is designed as to ensure a global carbon budget shall guide the emission reductions targets and actions of all Parties, whereas the global carbon budget for 2020 is defined as no higher than 36.1 GtCO2e and the budget for 2050 shall be no higher than 7.2 GtCO2e. Meeting these global emission budgets would require effort sharing where the criteria of responsibility, capability and potential to mitigate should be applied and taking into account the principle of common but differentiated responsibility, equity and fairness. The proposal formulates for Annex B parties (developing countries not having an emission target) the need to stay as a group within a carbon budget of no more than 25 Gt CO2e for all aggregated industrial anthropo-genic carbon dioxide equivalent emissions of greenhouse gases during 2013 to 2017. It is further proposed that these countries should undertake nation-ally appropriate mitigation actions (NAMAs) that are driven by their sustainable development objectives. NAMAs include but are not limited to sectoral approached, the use of the carbon market mechanisms and sustain-able development and policies. Regarding the CDM, the proponents of this Proposal voiced that the CDM has failed so far to create large sustainable development benefits for devel-

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oping countries due to the lack of standards on how to assess sustainability. A further lesson learnt is that market based financing does not provide the needed capacity building as. Two directions are mentioned in this respect: • The Clean Development Mechanism (CDM) needs to be fundamentally

restructured to better serve sustainable development and activities should be limited to Least Developed Countries and other developing countries with little capacity to act.

• For advanced developing countries, new carbon market mechanisms that provide incentives for long-term low-carbon development planning on a sectoral or economy wide level, should be created.

The proposal is not very specific on the details of the CDM reform. Also it remains open how NAMAs will/will not be treated in the overall carbon market.

12.4.3.6 DIRECTIVE 2009/29/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL, 23 April 2009

The European Union Emissions Trading Scheme (EU-ETS) has agreed Directive 2009/29/EC of the European Parliament and the Council amend-ing Directive 2003/87/EC so as to improve and extend the greenhouse gas emission allowance trading scheme of the Community. The next trading period will start 2013 and is scheduled till 2020. The European Council of March 2007 made a firm commitment to reduce the overall greenhouse gas emissions of the Community by at least 20 % below 1990 levels by 2020, and by 30 % provided that other developed countries commit themselves to comparable emission reductions and economically more advanced developing countries contribute adequately according to their responsibilities and respective capabilities. By 2050, global greenhouse gas emissions should be reduced by at least 50 % below their 1990 levels. Once an international agreement on climate change has been reached, additional credits of up to half of the additional reduction taking place in the Community scheme may be used, and high quality CDM credits from third countries should only be accepted in the Community scheme from 2013, once those countries have ratified the international agreement. Reference is given further to credits arising from LDCs. The above implies that the current system may allow only certain credits to enter the EU-ETS. What means a 'high quality CER' is not further explained in the text. Further, Vietnam is not an LDC country. Therefore, it remains open whether or not credits accruing from wind power projects in Vietnam would be eligible to enter the EU-ETS Post 2012 trading phase.

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12.5 Conclusion

The additional costs from the remuneration of 629 MW of wind power by 2016 amounts to maximum of 116 million USD per annum in 2016. In case no new wind power plants will be erected under the feed-in regulation after 2016, the additional costs will constantly decrease thereafter. If these extra costs are evenly distributed among all power consumers then the specific burden per kilowatt hour consumed amounts to a maximum of 0.0006 USD/kWh, i.e. six hundredth of one US cent. Even when the extra costs are only put on household consumers, then the specific burden would be 0.0018 USD/kWh at maximum or 3.3 % of present power tariffs. We deem that this is a very affordable and modest burden. There are no voices currently that CDM should be abolished. Instead, there is currently much discussion on its overall effectiveness and efficiency, which seems to have suffered since it was operationalized. The continuation of CDM for a post 2012 period (e.g. 2013 to 2017) has to be seen in the larger context of a new to be negotiated international treaty on climate change. There may be new approaches for CDM such as sectoral approach, which will put the question of baseline determination and emis-sion reduction calculation procedures back on the agenda. Further, NAMAs (Nationally Appropriate Mitigation Actions) are proposed as a new means to ensure developing countries are developing as per a low carbon development path. It remains to be seen how the Parties negotiate and finally decide on NAMAs. It also remains to be seen how NAMAs may interact with the CDM and what project types may move to a NAMA. NAMAs are proposed to be financially supported by public and private sector funding and by means of the Copenhagen Climate Facility that is proposed to recover the financing from sales of AAUs. It can be assumed that a NAMA, if it results in a greenhouse gas emission reduction, can not earn carbon credits in contrast to a CDM project. All these details are to be negotiated. It is therefore difficult at this stage - if not impossible - to assess whether normal CDM wind energy projects or CDM wind energy projects designed and operated as PoA would still be eligible to generate carbon credits since it will greatly depend upon whether such a project remains under the CDM umbrella or moves to a NAMA. A much clearer assessment could be done after the next COP/MOP in Copenhagen in December 2009. Finally, the rules for EU-ETS next trading phase will determine the eligibil-ity of carbon credits to enter the Community system. To date there is no clarity whether credits from wind power projects in Vietnam would be classified high quality credits. Further, Vietnam is not classified an LDC (Least Developed Country) from which EU may prefer to allow CERs into the market. There is a realistic option to implement wind power projects in Vietnam as CDM PoA as the formal framework does not represent an obstacle. How-

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ever several questions remain open when it comes to the final assembly. GEF funds might be used to develop further the idea of PoA and prepare relevant Project Documentation for submission to the UNFCCC. The suitability of GEF support to refinance in part the additional expenses remains open at this stage as a project proposal would have to be formulated and put forward for discussion initially with Country GEF representatives. The VEPF is considered not suitable for refinancing the extra costs as it is primarily open for private sector businesses and environmental protection agencies' investments.

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13. Carbon Dioxide Mitigation Calculation

13.1 Clean Development Mechanism (CDM) and the contribution to the development of renewable energy & wind energy in Vietnam

Develop the renewable power in association with CDM As the Strategy and Master Plan on Renewable Energy Development in Vietnam for the period to 2015 and outlook to 2025 submitted to Vietnam Government for approving, Vietnam has the plan to develop 629 MW of wind power (base scenario) and 1780 MW of wind power (high scenario) to connect the national grid. CDM can be applied for all scenarios of wind power development (grid connected) as mentioned above since Vietnam is a developing country and not listed in Annex I. Revenues of Certified Emis-sion Reductions (CERs) from the wind power projects will bring an extra income (improvement of cash flow), helping to increase FIRR by approxi-mately 3-6% compared to the basic solution. The range of IRR improve-ment depends on the project type. Formation of CDM legal framework in Vietnam Vietnam ratified the United Nation Framework Convention on Climate Change (“UNFCCC”) on 16 November 1994 and Kyoto Protocol (“KP”) on 25 September 2002. Since then, the government has issued a number of legal documents and guidelines on UNFCCC and KP implementation. Many of them are related to the Clean Development Mechanism (“CDM”) under KP including: • Directive No. 35 /2005/CT-TTg dated 17 October 2005 of the Prime

Minister on the implementation of Kyoto Protocol to the UNFCCC, which instructs various ministries and government agencies as well as provincial/municipal People’s Committees to implement the Clean De-velopment Mechanism (CDM) of KP effectively;

• Decision No. 47/2007/QD-TTg dated 06 April 2007 of the Prime Minister regarding National Plan for Kyoto Protocol Implementation in the period 2007-2010;

• Decision No. 130/2007/QD-TTg dated 2 August 2007 of the Prime Minister on a number of financial mechanisms and policies for CDM projects in Vietnam;

• Circular No. 10/2006/TT-BTNMT dated 12 December 2006 of Ministry of Natural Resources and Environment with regards to guidelines for developing CDM projects in Vietnam;

• Circular No. 58/2008/TTLT-BTC-BTN&MT dated 4 July 2008 of Ministry of Finance providing guidelines for executing some articles of Decision No. 130/2007/QD-TTg dated 2 August 2007, issued by the Prime Minister on a number of financial mechanisms and policies for CDM projects in Vietnam.

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The Ministry of Natural Resources and Environment (“MONRE”) was designated as the National Focal Agency for UNFCCC and Kyoto Protocol Implementation in Vietnam. MONRE then assigned its International Coop-eration Department (“ICD”) as the National Designated Authority (“DNA”) from March 2003 to April 2008. In March 2008, Department of Meteorol-ogy, Hydrology and Climate Change was established and started taking over the role of ICD as Vietnam DNA since May 2008. The Vietnam CDM National Executive and Consultative Board (CNECB) was established in April 2003 with twelve representatives from ten minis-tries and governmental agency (i.e. MONRE, Ministry of Foreign Affairs, Ministry of Finance, Ministry of Planning and Investment, Ministry of Science and Technology, Ministry of Industry, Ministry of Agriculture and Rural Development, Ministry of Education and Training, Ministry of Trade and Vietnam Union of Science and Technology Associations). Main func-tions of CNECB include providing consultancy to MONRE on policies related to development, implementation and management of CDM activities as well as participating in the process of reviewing and assessing project design documents (“PDD”) submitted for approval. CNECB was then replaced by the Vietnam National Steering Committee for UNFCCC and KP established on 4 July 2007 with 16 representatives from 15 ministries and governmental agency (i.e. MONRE, Ministry of Foreign Affairs, Ministry of Finance, Ministry of Planning and Investment, Ministry of Science and Technology, Ministry of Industry, Ministry of Agriculture and Rural Development, Ministry of Education and Training, Ministry of Trade, Ministry of Construction, Ministry of Transport and Communication, Ministry of Justice, Ministry of Culture and Information, Ministry of Labor, War Invalids and Social Welfare and Vietnam Union of Science and Tech-nology Associations).

13.2 Methodology tool

13.2.1 Identify baseline

Wind power projects that are proposed for construction as mentioned in the base scenario (629MW) will generate and sell net electricity to national grid. So that, the expected emission reductions will be calculated based on the net electricity selling to the national grid and the combined margin CO2 emis-sion factor of the national grid of Vietnam. The emission reduction of wind power projects will be related to the base-line which reflects the emissions that would occur in the absence of the wind projects. The emission reduction depends further on the type of project and its calculation is depicted in each methodology approved by the CDM-EB. The amount of reduced emissions is based on the baseline scenario and on the projects and leakage emissions. The difference between the baseline emissions and the project and leakage emissions is the project emission reduction. For grid-connected wind power projects the following will be applied

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ERY = BEy - PEy - LEy where ERy = Emission reduction in year y (tCO2/yr) BEy = Baseline emissions in year y (tCO2/yr) PEy = Project’s emissions in year y (tCO2/yr) LEy = Leakage emissions in year y (tCO2/yr) For grid-connected wind power projects the approved consolidated method-ology ACM0002 determines that renewable energy projects connected to an electricity grid are reducing CO2 emissions in an electricity grid system by displacing electricity which otherwise would have been generated by grid-connected fossil fuel power plants and by the addition of new generation sources. Thus, baseline emissions include only CO2 emissions from elec-tricity generation in fossil fuel fired power plants that are displaced due to the project activity. The baseline emissions are calculated by multiplying the displaced net electricity generation of connected fossil fuel power plants, which is equal to the electricity generation of the project activity, by the CO2 emission factor of the electricity system. The grid emission factor is calculated according to the "Tool to calculate the emission factor for an electricity system" (EB35, Annex 12, Version 01.1 and determines how much CO2 emissions are released into the atmosphere by a given electrical grid to produce 1 MWh.

BEy = EGy *EF grid CM y Where BEy = Baseline emissions in year y (tCO2/a) EGy = Amount of net electricity generation that will be produced and supplied to the grid as a result of the implementation of the CDM project activity in year y (MWh/a) EFgrid,CM,y= Combined Margin CO2 emission factor of the electricity grid in year y (tCO2/MWh)

13.2.2 National electricity grid emission factor calculation

13.2.2.1 Backgrounds for study, calculation of the emission factors (EF) of Vietnam electric power network

Calculation of EF for Vietnam electric power network is performed based on the following legal background: • Directive by the Prime Minister in the Announcement No. 152/TB-VPCP

dated 01/07/2008 by the Government Office entrusting the Ministry of Natural Resources and Environment, in coordination with Ministry of Industry & Trade, to carry out calculation of national GHG emission level in the power sector.

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• The paper No. 971/BTNMT-KTTVBDKH dated 01 April 2009, by Ministry of Natural Resources and Environment on performing calcula-tion of emissions in power sector of Vietnam and requesting coordination of Ministry of Industry and Trade in implementation of duties entrusted in the Announcement No. 152/TB-VPCP.

• The paper No. 4680/BCT-NL dated 22 May 2009 by Ministry of Industry and Trade sent to Electricity of Vietnam Group (EVN) and power plants operating in the power system, asking on provision of official data for calculation of GHG emissions factor in the power sector.

• Official data from EVN and power plants in Vietnam power network in accordance with request in the paper No. 4680/BCT-NL dated 22 May 2009 by Ministry of Industry and Trade attached with formats of data to be provided.

• The latest methodology published on the website of United Nations Framework Convention on Climate Change (UNFCCC) for calculation of emission factors for electric power systems, applied for CDM projects. The latest applicable and valid version of methodology ACM0002 is Version 10, which was published at EB meeting 47 (28 May 2009).

13.2.2.2 Brief description of the methodology

The calculation of emission factors for existing power systems in Vietnam will be based on the above mentioned methodology with consideration of attached guidelines and conditions of application and also based on use of the available that can be collected in Vietnam in the most reasonable, eligible and manageable way.

13.2.2.3 Calculation of GHG emission factors for Vietnam national power network

Current status of thermal power plants connected to the national power grid According to the report No. 2594/EVN-KHCN&MT dated 23 June 2009 by EVN on amount of electricity generated to the national power grid of Vietnam which will be used for calculation of the emissions of the power network and sum-up report of the national power network operation in 2008, prepared by the National Load Dispatch Center, January 2009, at present (data as of 32/12/2008), there are three types of electricity supplied to the Vietnam power network as follows: • From power plants of EVN • From power plants outside EVN, and • Imported from other countries The power plants of EVN and power plants outside EVN (IPPs) consist of hydropower plants (including the small hydropower plants); Coal fired power plants; oil fired power plants; Gas turbines burning gas; Gas turbines burning oil; Add-on steam turbines in GTCC power plants, Diesel genera-tors and biomass power plants (using bagasse).

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At present, there is only one coal fired power plant using imported coal – bitumen coal imported from Indonesia. The other coal fired power plants (both of EVN and outside EVN) use domestic anthracite coals. Gas thermal power plants with gas turbines use domestic gas, including TPPs with single cycle (gas turbine using gas) and gas turbine combined cycle (with add-on steam turbines). The evolution of the installed capacities of power plants in the Vietnam power network, categorized by type of fuel in the period 2000-2008 is presented in the Table 1 below. The details of the latest year (2008) which are shown in the Table 2 indicate that the share of hydropower tends to decline from 51.9% in 2000 to 33.4% in 2008. The share of IPPs outside EVN is increased from 7.2% in 2000 to 32% in 2008. (See Tables 1 and 2 in Annex 4) Electricity imported from China is increased in recent years. Imported electricity is only 39 million kWh in 2004, but after 5 years (in 2008), this figure reached 3.22 billion kWh.

13.2.2.4 Identifying scope and resource of data for calculation of emission factors

Power plants, power units in the power systems According to the guidelines for using methodology ACM0002 and based on the current status of Vietnam power network, all power plants such as hydropower plants (including those with capacity less than 30MW); coal fired power plants; oil fired power plants; gas turbines burning gas; gas turbines burning oil; add-on steam turbines in GTCC power plants, diesel generators and biomass power plants (using bagasse) which are being connected to the national power network shall be surveyed and their data will be collected for the calculation of the Combined Margin CO2 grid emission factor. Electric power network According to the methodological "Tool to calculate the emission factor for an electricity system" presented in the EB’s Report No. 35, the scope of calculation for Vietnam national power network is interconnected with Chinese power network at the northern region for importing its electricity. Because at present Vietnam power network is buying electricity from Chinese power system, therefore, the imported electricity portion shall be included in the electricity production of the whole power network but GHG emission will not be taken into account (equal to zero) in the process of calculation of the Operating Margin (OM), Build Margin (BM) and Com-bined Margin (CM) CO2 grid emission factor.

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Resource of data to be used in calculation For selection and performance of the various calculation steps, the following data needs be collected: • If calculation follows simple OM,

• Data of fuel consumption and electricity production of each unit/power plant) or

• Data of net electricity production, average efficiency of each unit and type of fuel used by each unit.

Or data of total electricity production of all power plants in the power network, types of fuel and total fuel consumption by the power network. • If calculation follows modified OM Data of power plants/units (including imported power) categorized into low cost power plants/must-be-operated power plants and other power plants • If calculation follows OM analysis of dispatch data

• Data of units actually dispatched per hour • Data of fuel consumption per hour

• If calculation follows average OM

• Data of average emission of all power plants which are connected to the national power network

• List of low cost/must-be-operated power plants • Calculation of BM emission factor

• List of 5 units which have been latest constructed, or • List of capacities added to the power network, which account for 20 %

of electricity production of the whole power network and latest con-structed.

Based on the available data which have been collected, the option i) of simple OM calculation is used for the period 2000-2008 is the most appro-priate. The procedure to determine the Build Margin (BM) CO2 grid emission factor is as follows: • list of 5 latest constructed units, or • list of the latest constructed power plants with added capacity accounting

for 20% of electricity production of the whole national power network. The step 5 of the above mentioned methodology is used for calculation of BM emission factor for Vietnam for period 2004-2008.

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Step 6 of the above mentioned methodology is used for calculation of CM emission factor for Vietnam power network for period 2004-2008 with factors wOM = 0.75 and wBM = 0.25 for wind projects. The results of emission factor calculation for Vietnam power network (combined margin emission factors) for years are as follows:

Emission factor Unit 2004 2005 2006 2007 2008

BM tCO2/MWh 0.6974 0.7469 0.5961 0.5729 0.5064

OM tCO2/MWh 0.8090 0.7311 0.6960 0.6795 0.6465

CM tCO2/MWh 0.7532 0.7390 0.6461 0.6262 0.5764 Table 13-1: Calculation of Emission Reduction To calculate CO2 emission reduction for wind project as mentioned in the base scenario, we need some assumptions for calculating as below: + Project’s emissions in year y (tCO2/yr) and Leakage emissions in year y (tCO2/yr) of wind project activities = 0 (tCO2/yr) + For the national electricity grid CM emission factor for base scenario (from 2008 to 2025) no change is assumed compared with national electric-ity grid average CM emission factor from 2004 to 2008. With these approaches, the national electricity grid average CM emission factor for 2004-2008 and amount of CO2 emission reduction for the period of 2009-2025 of wind power development scenario as mentioned below

Emission factor Unit 2004 2005 2006 2007 2008

BM tCO2/MWh 0.6974 0.7469 0.5961 0.5729 0.5064

OM tCO2/MWh 0.8090 0.7311 0.6960 0.6795 0.6465

CM tCO2/MWh 0.7532 0.7390 0.6461 0.6262 0.5764

CMaverage tCO2/MWh 0.6682 0.6682 0.6682 0.6682 0.6682 Table 13-2: Resulting average combined margin for CO2 emissions. As a result, the mitigated CO2 emissions are calculated as follows.

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Table 13-3: Amount of CO2 emission reduction

year Content 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Net electricity (GWh) 91 147 234 528 749 1084 1457 1598 1598 1727 1727 1727 1727 1727 1727 1727 1727

Emission factor (kgCO2/kWh) 0.6682 0.6682 0.6682 0.6682 0.6682 0.668 0.668 0.668 0.668 0.668 0.668 0.668 0.668 0.668 0.668 0.668 0.6682

Emission reduction (KtCO2/year) 60 98 156 352 500 724 973 1067 1067 1154 1154 1154 1154 1154 1154 1154 1153.98

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14. References

[BMU02] German Federal Ministry of the Environment, Environmental Protection and Reactor Safety 2002, “Erfahrungsbericht der Bundes-regierung zum EEG” (http://umweltministerium.de/erneuerbare/energien/doc/2677.php)

[BMU09] German Federal Ministry of the Environment, Environmental Protection and Reactor Safety 2009, “Informationspapier des BMU zum VDEW-Vorschlag eines sog. "Integrationsmodells" zur Förderung der Erneuerbaren Energien im Strombereich“ (http://www.erneuerbare-energien.de/inhalt/35619/4594/)

[BWE09] Bundesverband Windenergie 2009, „Vergütungsmodelle für Windstrom im Vergleich“ (http://www.wind-energie.de/de/themen/verguetungsmodelle/

[CER09] Central Electricity Regulatory Commission, “CERC notifies tariff regulations for green power” (http://www.cercind.gov.in/2009/September09/Press-Release_17.09.09_RE%20regulations.pdf9

[COE09] EEG Clearing Office 2009, “Müssen EEG-Anlagen nach dem EEG 2009 registriert werden, um die Vergütung zu erhalten?“ (http://www.clearingstelle-eeg.de/node/541)

[CSA96] Constitution of Vietnam, 1992 [CircC09a] Regulation of Electricity Price and implementing instructions (Circular

05/2009/TT-BCT) [DEC06a] Decision of the Prime Minister on milestone and condition for the establishing

and developing different electricity market level in VN (Decision 26/2006/QD-TTg)

[DEC07a] Decision on National power development for the period 2006-2015 with outlook to 2025 (110/2007/QD-TTg)

[DEC07b] Decisions on some mechanisms and policies for CDM Project (Decision 130/2007/QD-TTg)

[DEC08b] Instructions from the MoF and MoNRE for implementing Decision 130/2007/QD-TTg dated 02/08/2007 of the Prime Minister on the financial policies and mechanism for CDM projects (Decision 58/2008/TTLT-BTC-BTN&MT )

[DEC08a] Regulations on Avoided Cost Tariff promulgated together with Decision 18/2008/QD-BCT

[DEC09b] Avoided cost Tariff for 2009 (Decision 74/QD-DTDL) [DEC09a] Decision of the Prime Minister adjusting the retail price of electricity in 2009

and implementing the electricity price under the market scheme from 2010 and 2012 (Decision 21/2009/QD-TTg)

[DEHST07] German Emissions Trading Authority (DEHSt) at the Federal Environment Agency, 2007, German CDM Manual Guidance for Applicants Version 1.0 2007

[DOCC05] Department of Climate Change, national department and reform commis-sion, Measures for Operation and Management of Clean Development Mecha-nism Projects in China, 2005, (http://cdm.ccchina.gov.cn/english/NewsInfo.asp?NewsId=905)

[DGV20] Decentralised government in Vietnam, Beren C.Vis, 2000, University of Groningen, http://www.jus.unitn.it/cardozo/Review/vietnam.htm

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[Eco09] Ecoworld 2009, “Wind Power in China” (http://www.ecoworld.com/fuels/wind-power-in-china.html)

[EEG08] Gesetz für den Vorrang Erneuerbarer Energien (EEG), (http://bundesrecht.juris.de/bundesrecht/eeg_2009/gesamt.pdf)

[EER08] Emerging energy research, 2008, “Wind Power development strategies in Europe” (http://www.emerging-energy.com/user/EuropeWindPowerMarketsand Strategies20082020344149826_pub/EuropeWindPromo.pdf)

[ERC09] European Renewable Energy Council 2009, “Renewable Energy Policy Review – UK”

[EuC09] The European Commission, “United Kingdom Renewable Energy Fact Sheet”

[EWEA09] European Wind Energy Association 2009, “Wind Power installed in Europe by the End of 2008”, (http://www.ewea.org/fileadmin/ewea_documents/ documents/statistics/2008_wind_map.pdf)

[EWE08] European Wind Energy Association 2008, Annual Wind Statistics (http://www.ewea.org/index.php?id=1665)

[EWE09] European Wind Energy Association 2009, “Global Installed Wind Capacity” (http://www.ewea.org/fileadmin/ewea_documents/documents/ press_releases/2009/GWEC_Press_Release_-_tables_and_statistics_2008.pdf)

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Renewable Energy“ [Men08] Universität Flensburg PD Dr. Roland Menges, „Ökonomische Aspekte

des Einspeisemanagements“, (http://www.clearingstelle-eeg.de/files/fg1/FG1-Menges.pdf)

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4890S11/FICHT-5530494-v1

Annex 1

Outline of Decree

1

__________

SOCIALIST REPUBLIC OF VIETNAM

Independence – Freedom – Happiness

________________________

DECREE

ON

FEED IN TARIFF FOR SMALL WIND POWER PLANTS

CHAPTER 1

GENERAL PROVISIONS

Article 1: Purpose 1. The purpose of this Decree is to set out a regulatory framework to establish a wind power Feed-In Tariff. The Feed-In Tariff shall promote the generation and use of electricity from wind energy in order to

a) facilitate a sustainable development of energy supply b) protect the climate and environment c) diversify supply resources and enhance energy security

2. To fulfill the purposes as set out in subsection 1 above, this Decree supports in achieving the targets of 564 MW and 629 MW installed wind energy capacity by 2015 and 2025 respectively. Article 2: Scope 1. This Decree is valid, and should be considered, for power plants which generate electricity from the renewable resource, wind, and feed their generated electricity from wind into the national transmission and distribution grid. 2. This Decree regulates the rules, requirements, responsibilities and obligations for all key parties involved and sets out the criteria for eligible projects as well as the tariff structure for electricity generated from Small Wind Power Plants. It stipulates conditions and procedures concerning preparation, amendment, supplementation and expiry of the electricity tariff to be applied to Small Wind Power Plants which are connected to the distribution and transmission grid.

2

Article 3: Definitions In this regulation, the terms below shall be construed as follows: Buyer: means the buyer pursuant to the terms of an SPPA. Commercial Operations Date: The day on which the SWE Generator commences deliveries of electric energy to Grid Operator pursuant to the terms of an SPPA. Connection Point: The point where SWE Generator’s electric output line feeds into the electric system of Buyer. Electricity Regulatory Authority Regulator (herein after referred to as ERAV): The entity legally responsible for power sector regulation in Vietnam. Electric Power Trading Company (hereinafter referred to as EPTC): means the entity of that name, which is a subsidiary of Electricity of Vietnam (EVN). Eligible Power Plant: means a power plant generating electricity from wind energy and which meets the conditions stipulated in the Chapter I, Article 2 of this Decree. Feed-In Tariff: The tariff applicable to qualifying Small Wind Power Plants, irrespective of time-of-day or season, as approved and issued by the ERAV Grid Operator: Power distribution unit or transmission unit which possesses all required licenses and requisite corporate and legal authority for the distribution or transmission and sale of electricity and which operates the electric system to which the SWE Generator’s facility will be connected. Kilowatt-hours (herein after referred to as kWh): Energy unit in which electricity generation is measured. List of Projects: The list of projects concerning Small Wind Power Plants calling for investment capital, which is formulated and published according to Chapter II, Article 3.1. Megawatt (herein after referred to as MW): A megawatt is a unit for measuring power that is equivalent to one million watts (equivalent to one joule per second). Non-negotiable Standardized Power Purchase Agreement (herein after referred to as SPPA): means the power purchase agreement issued by the Ministry of Industry and Trade, and under which a Small Wind Power Plant is the seller to whom a Feed-In Tariff applies.

3

Renewable Energy Finance and Subsidy Fund (herein after referred to as REFSF): means the national fund under the Ministry of Industry and Trade established to support and promote the activities of renewable energy development. Renewable Energy Development Office (herein after referred to as REDO): Office for renewable energy development which will manage and control renewable energy promotion activities on behalf of the Vietnamese government. Small Wind Power Plant: A facility generating up to 30MW installed power output capacity generated from wind. A Small Wind Power Plant may consist of several wind turbines. Small Wind Energy Electricity Generator (herein after referred to as SWE Generator): The owner of a Small Wind Power Plant, which: (a) is a company duly organized and validly existing under the laws of the

Government of Vietnam; (b) possesses all required licences and requisite corporate and legal authority to

execute the SPPA; and (c) is permitted to sell independently produced power to the Grid Operator. Wind Energy Potential Area (herein after referred to as WEPA): means a wind energy potential area as identified and published by the authorized body in accordance with Chapter II, Article 3.3. Wind Turbine: A single wind turbine generating system, including the tower, pad, transformer and controller system, which is part of the Small Wind Power Plant.

CHAPTER II

ELIGIBLE TECHNOLOGIES AND POWER PLANTS

Article 1: Eligible technologies 1. The following technology is an eligible technology for the purposes of this decree:

a) Wind power 2. More renewable technologies may be added in further phases of the Decree. Article 2: Eligible power plants Wind power plants eligible for the Feed-In Tariff must feature the following properties:

a) located in the Socialist Republic of Vietnam;

4

b) must be designed to feed their generated electricity from wind into the national distribution and transmission grid of the Socialist Republic of Vietnam;

c) no larger capacity than 30 MW (must be a Small Wind Power Plant); d) cannot have been commissioned more than three years before the date of this

Decree; e) must bear a generation licence issued by REDO; f) must be the subject of a project in the List of Projects; and g) must either:

(i) be planned to be wholly situated in a WEPA; or (ii) if the project is not planned to be wholly situated in a

WEPA, or if the WEPA have not yet been established in accordance with Article 3(2), be the subject of a Feed-In Tariff application which is accompanied by wind measurement data relating to the proposed site and relating to a period of at least one recent year.

Article 3: Establishment of valuation criteria for Feed-In Tariff application

1. Establishment of the List of Projects

a. Within 12 months of the date of this Decree, the authorized bodies must complete the master plan on renewable energy for socio-economic development with reference to the Decree No. 78-2007-ND-CP so that categories of wind energy density in potential areas are classified and potential investment projects in wind energy are proposed.

b. Within 24 months of the completion of the master plan in accordance with

paragraph (a), the authorized bodies shall formulate, approve and publish a list of projects which are calling for investment capital (List of Projects).

c. Where an investor wishes to apply for a Feed-In Tariff in relation to a

project that is not among the published List of Projects:

i. the investor must prepare, collect and submit all current feasibility data regarding the project and undertake completion of all other necessary procedures for licensing;

ii. once the investor submits the data to the authorized body, that body must either update the List of Projects to include the new project or reject inclusion of the new project in the List of Projects and provide reasons to the applicant for that rejection.

iii. A project will automatically enter the List of Projects two months after application according to this section if the application is complete and the authorized body has not positively rejected the application with reasoning.

5

2. Establishment of a SPPA

a. On the same date as that of this Decree, the Ministry of Industry and Trade will publish the standard SPPA which applies pursuant to this Decree.

b. The Ministry of Industry and Trade must review the terms of the SPPA once every four years to assess the appropriateness of its terms. Where it deems it reasonably necessary, the Ministry of Industry and Trade may amend the SPPA applying to future Small Wind Power Plants.

3. Establishment of WEPA

The authorized body shall:

a. Within 2 years of the date of this Decree, propose wind energy potential areas (WEPA) grouped according to categories of power density for license applications;

b. in a timely manner, publish on its website maps of these WEPA areas, and data concerning power densities, reference installed power capacities and annual amount of electricity that can be generated with that installed power capacity; and

c. once WEPA have been established in accordance with (a), provide the legal entities intending to file Feed-In Tariff applications regarding projects situated wholly or partly in WEPA with information about the topographical characteristics of the area, wind characteristics, turbine coordinates, and any relevant environmental, ownership, usage and transportation statutes upon the legal entities’ request.

CHAPTER III

TARIFF STRUCTURE

Article 1: Tariff setting The Feed-In Tariff rate set in this Article has been established with reference to the results of an assessment of expected typical generation costs of a Small Wind Power Plant. The Feed-In Tariff will be paid for electricity generated from qualifying Small Wind Power Plants and shall amount to 10.5 US cents per kilowatt-hour for those Small Wind Power Plants commissioned in 2010. Article 2: Commencement and guaranteed payment period 1. A qualifying SWE Generator will receive guaranteed Feed-In Tariff payments,

including annual inflation adjustment in accordance with Article 3, for a term of 20 years, measured from the commercial operation date.

2. After the guaranteed payment time of 20 years, the SWE Generator will receive

the current market electricity prices of the Socialist Republic of Vietnam.

6

Article 3: Tariff adjustments

1. Inflation adjustment The Feed-In Tariff will be adjusted annually by the annual increase, if any, in the consumer price index of the Socialist Republic of Vietnam by using the following Feed-In Tariff adaption rule:

aa

ii T

II

T ⋅⋅+= )3.07.0(

with 0.7: Share of tariff not effected by inflation 0.3: Share of tariff effected by inflation Ti : Feed-In Tariff in year i of operation of an individual plant Ii : Vietnamese consumer price index in year i of operation of an individual

plant Ia : Vietnamese consumer price index in year a start of operation of an

individual plant Ta : Feed-In Tariff in year a start of operation of an individual plant

2. Tariff degression

The Feed-In Tariff provided in Article 1 of this Chapter III shall apply to approved Small Wind Power Plants commissioned in 2010. In the case of approved Small Wind Power Plants commissioned in subsequent calendar years, the Feed-In Tariff shall be reduced progressively each year. Once a Small Wind Power Plant has already been commissioned and a Feed-In Tariff rate has been attributed to that plant, that attributed Feed-In Tariff rate will remain constant for the guaranteed payment duration of support except the annual inflation adjustment. The annual percentage degression for the Feed-In Tariff relating to electricity generated from wind energy shall be 1.6%.

3. Progress report for periodic regular adjustments

REDO must prepare a progress report in relation to the appropriateness of the rate of the Feed-In Tariff: a. once every four years, beginning on the date of this Decree; and b. when the targets according to Chapter I, Article 1(2) are reached. On consideration of the progress report specified in this paragraph 3, the Ministry of Industry and Trade may revise and adjust the Feed-In Tariff where it reasonably deems it necessary.

7

Article 4: Tariff funding The Grid Operator is entitled to recover its additional costs incurred as a result of this Decree from the Renewable Energy and Subsidy Fund (REFSF).

CHAPTER IV

CONNECTION OBLICATION AND PURCHASE OBLIGATION

Article 1: Grid connection, reinforcement and costs 1. SWE Generators shall be guaranteed access and connection to that point in the grid system which is suitable in terms of the voltage and which is physically the nearest point from the location of the Small Wind Power Plant. 2. A SWE Generator and the Grid Operator may agree on a grid connection point other than that specified in paragraph 1. 3. The Grid Operator’s obligation to connect the Small Wind Power Plant to the grid system also applies when optimizing, reinforcement or expanding measurements of the grid are necessary to connect and transmit the electricity. 4. The Grid Operator shall, at the written request of a SWE Generator, immediately optimize, reinforce, boost and expand the grid where this is necessary in order to guarantee the purchase, transmission and distribution of the electricity generated from wind energy. 5. A SWE Generator shall pay for the costs of the equipment needed to connect its Small Wind Power Plant to the Connection Point. 6. The costs for reinforcement, optimizing or expanding of the grid necessary to connect any Small Wind Power Plant to the grid, will be paid by the Grid Operators. Article 2: Purchase obligation 1. The Grid Operator shall be obligated to buy the electricity generated from approved Small Wind Power Plants at the Feed-In Tariffs set by this Decree. 2. The buyer of the electricity shall be obligated to enter into a SPPA with the SWE Generator.

8

CHAPTER V

MONITORING, REPORTING, REVIEW

Article 1: Renewable Energy Development Office (REDO) 1. The REDO shall be responsible for overall monitoring and review of all matters relating to this Decree, including:

a) Data on the energy purchased under the SPPA’s per technology band and the total cost of the Feed-In Tariff scheme (the data which shall be gathered and maintained by the REDO).

b) To prevent over subscription to this Feed-In Tariff scheme, the REDO shall be permitted to bring in capacity limits on specific technologies in the future and prioritize the types of technology that have a lower Feed-In Tariff.

c) The REDO shall be responsible for monitoring the operation of the REFSF. d) By 1st June every year after the implementation of this Decree, the REDO shall

publish a summary report regarding the implementation of this Decree and the progress in achieving the objectives of the Decree as outlined in Chapter 1, Article 1(2). This report shall include the following:

(i) Progress on the 2015 Renewable Energy Target and future national renewable energy targets;

(ii) Update on the market introduction of the qualifying technologies including number of applications received, number of applications approved and number of projects implemented, detailing technology, size and geographic location;

(iii)Financial impacts of the Feed-In Tariff scheme including the additional overall cost to electricity consumers and average percentage increase on electricity prices;

(iv) Changes or additions in qualifying technologies.

Article 2: Renewable Energy Finance and Subsidy Fund (REFSF) 1. Every three months from the date of this Decree, the REDO shall publish a summary report in relation to the REFSF revenues and expenses. 2. Every year from the date of this Decree, the REDO shall on or before 31 March, publish a summary report in relation to the REFSF’s performance in the outgoing year and will particularly report on:

(a) the REFSF’s overall revenue and expenses for the outgoing year and any other information relevant to the financial situation of the REFSF; and

(b) plans for spending funds from the REFSF in the upcoming year.

9

Article 3: Electricity Regulatory Authority of Vietnam (ERAV) 1. The ERAV shall be responsible for the overall reporting on the electricity production from renewable energy sources to the REDO. 2. The ERAV shall ongoingly liaise with Electricity of Vietnam and the National Load Dispatch Centre to monitor dispatch issues arising from the connection and generation of electricity under the Feed-In Tariff scheme. 3 Every year after the implementation of this Decree by 31 March the ERAV shall provide REDO with a report on the progress of the practical implementation of this Decree and the progress achieved in relation to this Decree’s objectives as provided in Chapter 1, Article 1(2). This report shall include the following:

a) Cost development and learning effect resulting from the market expansion of the technologies.

Article 4: Small Wind Power Electricity Generators (SWE Generators) 1. An SWE Generator remains required to adhere to the Vietnam grid code and Vietnam distribution/transmission grid code regarding planning information, operational information and post-dispatch information. 2. Once every 6 months, an SWE Generator must in relation to its approved Small Wind Power Plant provide a report to the ERAV which outlines device status, plant capacity and electrical energy production as well as any problems in managing or operating the Small Wind Power Plant. 3. In addition to the monitoring and reporting requirements under the generation license conditions, an SWE Generator operating an approved Small Wind Power Plant is obligated to submit annual renewable energy generation reports to the ERAV in relation to each year ending 31 December by 1st February of the following year. The report shall in relation to the outgoing year detail:

a) The net maximum capacity of the wind energy generation (MW) b) The renewable energy output fed into the grid by the SWE Generator (MWh) c) Any problems or anticipated problems in managing or operating the Small Wind

Power Plant d) Comments and feedback on the progress and success of the Feed-In Tariff scheme

from the perspective of the SWE Generator. Article 5: Electric Power Trading Company (EPTC) 1. The EPTC shall monitor, and report once a year from the date of this Decree to the ERAV on power production of SWE Generators. 2. By 30th November each year, EPTC in conjunction with the ERAV shall prepare a projection on the estimated take up of new connections and power generation for the following year.

10

3. By 31st March each year, the EPTC shall report to the ERAV on: (a) the cost of the energy purchased under the Feed-In Tariff in the previous year over and above the avoidable costs; and (b) any additional costs associated with the implementation of Feed-In Tariffs, including wheeling charges and costs incurred in the management and implementation of the feed in tariff by EPTC. Article 6: Summarized monitoring reporting requirements The monitoring and reporting requirements provided in this Decree are summarized in the following table:

Reporting Institution

Addressee of Report

Subject of Report Frequency of Report (from the

date of this

Decree) Renewable Energy Development Office (REDO)

General public

• Summary report on the implementation of the Decree and progress in achieving the objectives of the Decree in accordance with Chapter V, Article 1(d)

By 1 June every year

REDO General public

• Summary report on the appropriateness of the Feed-In Tariff rate in accordance with Chapter III, Article 3(3)

Once every four years

REDO on behalf of the REFSF

General public

• Summary report regarding REFSF’s revenues and expenses in accordance with Chapter V, Article 2(1)

Four a year

REDO on behalf of the REFSF

General public

• Summary report regarding the REFSF’s overall revenue and expenses for the outgoing year and any other information relevant to the financial situation of the REFSF

• Summary of plans for spending funds from the REFSF in the upcoming year

in accordance with Chapter V, Article 2(2)

By 31 March, once a year

11

Electricity Regulatory Authority of Vietnam (ERAV)

REDO

• Electricity production from renewable energy sources

• Progress of practical implementation of the Decree and the progress achieved in relation to the objectives of the Decree in accordance with Chapter V, Article 3(3)

By 31 March, once a year

Small Wind Energy Electricity Generators (SWE Generators)

ERAV • Device status, capacity and electrical energy production, problems of managing and operating Small Wind Power Plants arising in practice in accordance with Chapter V, Article 4(2)

Every six months from the date of notification of Feed-In Tariff

ERAV • Net maximum capacity of the renewable energy generation (MW);

• Renewable energy output fed into the grid by the SWE Generator (MWh);

• Comments and feedback on the progress and success of the Feed-In Tariff scheme from the perspective of the SWE Generator

in accordance with Chapter V, Article 4(3).

By 1 February, once a year

Electric Power Trading Company (EPTC) and ERAV

Internal use • Projection on the estimated uptake of new connections and power generation for the following year in accordance with Chapter V, Article 5(2)

By 30 November, once a year

Electric Power Trading Company (EPTC)

ERAV • Power production by SWE Generators

• Projection on the estimated take up of new connections and power generation for the following year

• Cost of the energy purchased under feed in tariff over and above Avoided Cost and all additional costs associated with the implementation of feed in tariff, including Wheeling Charges and costs incurred in the management and implementation of feed in tariff

in accordance with Chapter V, Article 5(3)

By 31 March, once a year

12

FOR MINISTER (signed and sealed)

4890S11/FICHT-5530494-v1

Annex 2 Standard Power Purchase Agree-ment for Purchase of Electric un-

der a Feed-In Tariff

1

NON-NEGOTIABLE STANDARDIZED POWER PURCHASE AGREEMENT

FOR PURCHASE OF ELECTRIC ENERGY

UNDER AN AVOIDED COST FEED-IN TARIFF

between

POWER COMPANY (BUYER)

and

A RENEWABLE ENERGY SMALL WIND POWER PLANT PROJECT POWER (SELLER)

September 2009

FIRST DRAFT

Prepared by

FICHTNER, Germany

2

CONTENTS

Article 1. Definitions...................................................................................................... 4

Article 2. Delivery, Sale, and Purchase of Entitlement ............................................... 76

Article 3. Connection, Metering, Operation ................................................................ 98

Article 4. Billing and Payment................................................................................. 1110

Article 5. Force Majeure .......................................................................................... 1312

Article 6. Term, Default and Termination ............................................................... 1413

Article 7. Dispute Resolution................................................................................... 1615

Article 8. Delegation and Assignment, Restructuring ............................................. 1716

Article 9. Miscellaneous .............................................................................................. 17

Article 10. Representations and Warranties............................................................... 1918

APPENDIX A. Rates for Delivery of Buyer's Entitlement

APPENDIX B. Description of Seller's Facility

APPENDIX C. Connection Requirements

APPENDIX D. Distribution Fees

3

POWER PURCHASE AGREEMENT

Pursuant to the Electricity Law dated December 3, 2004;

Pursuant to the Law on Trade dated June 14, 2005;

Pursuant to the Regulations on Avoided Cost Feed-In Tariff promulgated by the Ministry of Industry and Trade together with the Decision No. ___ dated ___;

Considering the Buyer's requirement to obtain electric energy and the Seller's wish to deliver and sell such electric energy,

Today, as of the ___ day of the month of ___ 20__ [year], at ____ [place]

We, including:

The Seller:

Address: __________________

Telephone: ________________ Fax: _____________________

Tax Code: _________________

Bank Account: _____________ Bank: ____________________

Represented by: ____________

Position: __________________ authorized by: ______________

In accordance with the Authorization paper number _____ [day] _____[month] ____ [year];

and

The Buyer:

Address: __________________

Telephone: ________________ Fax: _____________________

Tax Code: _________________

Bank Account: _____________ Bank: ____________________

Represented by: ____________

Position: __________________ authorized by: ______________

In accordance with the Authorization paper number _____ [day] _____[month] ____ [year];

NOW, THEREFORE, in consideration of the mutual promises and agreements contained herein, the sufficiency of which are stipulated by the Parties, Seller and Buyer hereby agree as follows.

4

ARTICLE 1. DEFINITIONS

When used with initial capitalizations, whether in the singular or in the plural, the following terms shall have the following meanings:

Agreement: This document, including all the following Appendices:

(1) Appendix A: The standardized tariff rates and escalators for purchase and sale of electric energy applicable to this AGREEMENTRates for Delivery of Buyer's Entitlement.;

(2) Appendix B: Description of Seller's Facility;.

(3) Appendix C: Connection Requirements;.

(4) Appendix D: Distribution Fees;

and all documents, laws, regulations, or standards incorporated by express reference herein, as such may be amended from time to time.

Avoided Cost Tariff: The tariff applicable to qualifying Renewable Energy Small Power Projects, as approved and issued by the Regulator based an the avoided cost of electricity in Viet Nam and published annually.

Buyer: Power distribution unit which possesses all required licenses and requisite corporate and legal authority for the distribution and sale of electricity and which operates the electric system to which the Seller's Facility will be connected.

Buyer's Entitlement: The Facility's capacity and associated entire electric energy, up to but not to exceed the maximum dependable load-carrying ability of the Facility as generated by the Facility at any given moment, irrespective of the period and time of generation, exclusive of energy required for Facility use, expressed in kilowatthours, agreed herein to be committed by Seller for sale and delivery to Buyer, as set forth in Appendix B of this AGREEMENT.

Commercial Operations Date: (1) A day following the day on which Seller notifies Buyer that power deliveries can commence consistent with the terms of this AGREEMENT, (2) on which day Seller commences deliveries of electric energy to Buyer that satisfy the AGREEMENT and obligate Buyer to pay for such energy deliveries.

Connection Point: The point where Seller's electric output line feeds into the electric system of Buyer.

Contract Year: The twelve month period beginning on the first day of January 1 and ending on the last day of December in any calendar year, except for the first Contract Year, which shall begin on the Commercial Operations Date and end an the last day of December in that first Contract Year, and except for the last Contract Year, which shall end on the final day of the Term set forth in Article 6.

Delivery Point: The point where the Seller's metering of power output initially takes place.

Distribution Code: The Code promulgated by the Ministry, applicable to operation of the distribution system and to the interconnection of Small Wind Power Plants Projects to the distribution voltage systems.

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Due Date: Fifteen (15) days after a monthly invoice from Seller is received by Buyer during the term of this AGREEMENT.

(o)Dry Season: The months of July through October of each calendar year.

Emergency: A condition or situation which is likely to result in disruption of service to Buyer's customers, is likely to cause a major fault in Buyer's distribution system, is likely to endanger life or property, or suddenly compromises the technical ability of the Facility to generate power.

Event of Default: An event as defined in subclause Article 66.2.

(r)Facility: All of Seller's electric generation equipment, together with all protective, connection, and other associated or auxiliary equipment and improvements of Seller, and rights to own or use land associated with such equipment, necessary to produce electric energy utilizing wind power pursuant to this AGREEMENT.

Feed-In Tariff: The tariff applicable to qualifying Small Wind Power Plants, irrespective of time-of-day or season, as approved and issued by the Regulator based an the estimated average cost of electricity generated by small wind power plants in Viet Nam.

Good Utility Practice: Those practices, methods, acts, standards, engineering and operational considerations consistent with law, regulations, codes, equipment manufacturers' recommendations, safety, law, and environmental protection, with regard to adequate materials, resources, supplies, fuel, personnel, maintenance, repairs, monitoring, testing, and operation generally accepted in the utility industry in Viet Nam and reflective of regional practices at a particular time, in the exercise of reasonable judgment based an the facts known or that should have been known at the time of a decision, that would have been expected to accomplish the desired result for operation and maintenance of power generation and distribution facilities.

(t)Lender: Any person or entity, or any agent of or trustee for such person or entity, providing debt financing and/or refinancing and/or loan guarantees to Seller or to Buyer to implement this AGREEMENT. The list of Lenders is designated by notice from time to time by a Party to the other Party pursuant to subclause Article 99.8 of this AGREEMENT.

Metering Code: The code promulgated by the Ministry applicable to metering and measurement of energy produced by Small Power Projects.

Ministry: The Ministry of Industry and Trade of Viet Nam, or its successor ministry or agency.

Must Take Facility: A Must Take Facility shall mean a Facility where Buyer must take and purchase all of the net electric energy output, not exceeding the dependable annual capacity, to be generated by the Facility and delivered and sold to Buyer, subject only to such necessary directions or protocols as may be issued by Buyer for the protection of its electric system.

(x)Normal Period: That portion of the hours of the year that are defined from time to time by the Regulator as Normal Period hours during either the wet season or the dry season.

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(y)Off-Peak Period: That portion of the hours of the year that are not defined from time to time by the Regulator as Peak Period or Normal Period hours during either the wet season or the dry season.

Party or Parties: Seller, Buyer, or both, and their successors in interest to any or all of the rights and obligations hereunder.

(aa)Peak Period: That portion of the hours of the year that are defined from time to time by the Regulator as the Peak Period hours during either the wet season or the dry season.

Prime Rate: The average short-term (one month) interbank lending rate of VN VNIBOR during the applicable period, provided that it does not exceed the highest lending interest rates of the Viet Nam bank(s) in which Seller maintains its bank accounts under this AGREEMENT.

Regulator: Electricity Regulatory Authority of Viet Nam (ERAV), or any successor entity legally responsible for Power sector regulation.

(dd)Renewable Energy: Renewable non-fossil energy sources, including solar photovoltaic, wind, geothermal, wave, tidal, landfill gas, sewage treatment plant gas, biogas or biomass (the biodegradable fraction of products, waste and residues from agriculture, including vegetal and animal substances, forestry and related industries, as well as the biodegradable fraction of industrial and municipal waste), employed as the primary energy source for the production of electricity (including cogeneration employing such sources) at a Small Power Project facility, or hydroelectric energy used for the production of electricity at a facility with a reservoir capacity and/or dam height below a threshold, as defined by the Ministry of Industry.

Scheduled Outage: An outage at the Facility which is scheduled in advance for the purpose of performing maintenance an the Facility.

1.14Seller: Seller is a company duly organized and validly existing under the laws of the Government of Viet Nam, possesses all required licenses and requisite corporate and legal authority to execute this AGREEMENT, and is permitted by applicable laws and regulations to sell independently produced power to Buyer.

Small Wind Power ProjectPlant: Aproject of plant with installed total capacity , exclusive of any water used or stored for non-electric production purposes, of up to thirty (30) MW or such other threshold as may be determined by the Ministry of Industry, and that generates electric energy exclusively by Renewable Energywind energy or Waste fuels, and sells energy pursuant to this AGREEMENT.

(gg)Surplus Energy: That portion of wet season electric energy output in excess of the amount of energy output that would be produced at a wet season load factor as defined from time to time by the Regulator..

Turbine: A single wind turbine generating system, including the tower, pad, transformer and controller system, which is part of the Seller's Facility.

Unscheduled Outage: An outage at the Facility which is not a Scheduled Outage.

1.15Waste: Discarded agricultural, industrial or solid waste employed as the primary fuel source for the electric generation of a Small Power Project facility.

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1.16Wet Season: The months of November through June of each calendar year.

ARTICLE 2. DELIVERY, SALE, AND PURCHASE OF ENTITLEMENT

2.1 Delivery, Acceptance and Purchase of Entitlement.

(1) Upon the Commercial Operations Date and thereafter Seller agrees to deliver and sell Buyer's Entitlement to Buyer for the term of this AGREEMENT as specified in Article 6 and at the price as specified in Appendix A.

(2) Acceptance and Purchase of Entitlement. Upon the Commercial Operations Date and thereafter, Buyer agrees and covenants to accept Buyer's Entitlement into its distribution system and to purchase for the term of this AGREEMENT as specified in Article 6 and at the price as specified in Appendix A.

(3) Environmental Attributes. Buyer shall be entitled to and shall retain all rights, titles and interests in any environmental attributes recognized under any international, national or other laws or regulations, associated with the ownership or generation of power from the Facility, including but not limited to carbon credits or attributes created pursuant to the Kyoto Protocol or any successor laws.

2.2 Operation of Facility. Seller agrees to operate the Facility to the maximum extent feasible consistent with the recommendations of equipment manufactures and Good Utility Practice. Buyer shall not assert Seller's liability for, and Seller shall not be liable to Buyer for, any direct damages resulting from Seller's unintended or accidental failure to deliver Buyer's Entitlement. Unless specifically allowed pursuant to this AGREEMENT, wWhere without Buyer's prior written approval Seller deliberately reduces Buyer's Entitlement for the purpose of selling or attempting to sell electric energy to any third party, or for the purpose of producing any other form of energy capable of being produced at the Facility in lieu of Buyer's Entitlement, said limitation of Seller's liability shall not apply.

2.3 Forecasts.

(4) Prior to or at the time of execution of this AGREEMENT, the Seller shall attach to this AGREEMENT a schedule consistent with the electric energy output assumptions used in the feasibility study for the Facility, stating expected net electric energy output for each month of the year. For a hydroelectric Facility, included shall be a schedule showing expected net electric output for each month of every year in the hydrologic record.

(5) Prior to December 1 of any Contract Year, Seller shall furnish to Buyer a one (1) year forecast of its anticipated operations that includes the following: (a) anticipated monthly generation availability, capacity and energy output, and (b) Scheduled Outages for each year; provided, however, Seller shall have no liability to Buyer and shall be subject to no liability, reduced payment, or penalty in the event that the actual amount of capacity and associated electric energy delivered to Buyer, or the times of said delivery, differ from the amounts or times shown in said forecasts.

2.4 Reporting. For monitoring purposes, Seller shall measure wind velocity, wind direction, and ambient temperate at the site of the Facility, and submit the measurement

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results to Buyer in a format to be mutually agreed between Seller and Buyer within fifteen (15) calendar days after the end of each month. The Seller shall report any other data to Buyer as required by, and according to the formats set by, the Regulator.If the one (1) year forecast provided hereunder is different by more than five percent (5%) in any month compared to the average generation provided pursuant to Article 2(e)(1), Seller at the time of this forecast shall provide Buyer in writing a justification explaining such difference, including any new hydrological or other relevant data that is the basis for such forecast. Seller shall also provide reasonable forecasts of daily expected Operation to the system Operator, if so required by the system operator. Notwithstanding this provision, Seller may not deliver to another party Buyer's Entitlement without the prior written consent of Buyer, except as provided herein. Seller shall promptly revise its Scheduled Outages and notify Buyer if such plans change.

2.5 Scheduled Outages. Seller shall attempt to coordinate any Scheduled Outage, subject to Good Utility Practice, with Buyer's reasonable written request. Seller shall notify Buyer three month in advance of Scheduled Outages, including a non-binding estimate of expected length of each outage, and as soon as possible, of any Unscheduled Outages, including a non-binding estimate of expected length of each outage.

2.6 Distribution System Operation. Buyer shall operate and maintain its distribution system and the Facility connection in accordance with the Distribution Code and Good Utility Practice so as to permit the delivery to Buyer's system of Buyer's Entitlement. Buyer shall work with the Seller to balance load and support voltage on its distribution system so as to maximize the ability of the Buyer distribution system to accept Buyer's Entitlement.

2.7 Interruption of Acceptance and Purchase. Notwithstanding that Seller's Facility is a Must Take Facility, Buyer shall not be obligated to purchase or take delivery of Buyer's Entitlement for that limited time period under the following conditions:

(1) if the Facility is not operated and maintained in a manner consistent with the Distribution Code and Good Utility Practice in accordance with Article 3;

(2) to the extent that such interruption, reduction or refusal is consistent with Good Utility Practice in order for Buyer to install equipment, make repairs, replacements, investigations or inspections of Buyer's distribution system;

(3) whenever Buyer's distribution system or the systems with which it is directly connected experience an Emergency or requires maintenance; or

(4) whenever it is necessary to aid in the restoration of service on Buyer's distribution system under the Distribution Code and Good Utility Practice.

2.8 Interruption of Delivery. Seller may interrupt, reduce or refuse to deliver Buyer's Entitlement only to the extent that Seller reasonably determines that such interruption, reduction, or refusal is necessary in order to install equipment in, make repairs, replacements, investigations and inspections of, or perform maintenance on the Facility which directly affect, the delivery of Buyer's Entitlement. Seller shall, prior to initiating any interruption, reduction or refusal to deliver Buyer's Entitlement, unless there is an Emergency, use its best efforts to provide Buyer a minimum of ten (10) days advance notice, such notice to include an explanation of the cause of the interruption, and an estimate of the start and duration of the interruption.

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2.9 Coordination. Because Seller's Facility is a Must Take Facility, Buyer shall use its best efforts to coordinate and to minimize any periods of interruption, reduction, refusal, or curtailment of acceptance of capacity or electric energy from Seller as provided for in subclause 2.72.8 of this Article with the periods of previous Scheduled Outage at the Facility. Prior to initiating any interruption, reduction or refusal of Buyer's Entitlement, unless there is an Emergency, Buyer shall use its best efforts to provide Seller with a minimum of ten (10) days advance notice, such notice to include an explanation of the cause of the interruption, and an estimate of the start and duration of the interruption. Where necessary, Buyer shall pass through to Seller instructions an voltage and Operation received from the system Operator that are applicable to Facility operations, and Seller shall comply with such instructions; provided however nothing in this section related to distribution system integrity shall change the basic designation of the Facility as a Must-Take Facility.

2.10 Power Factor. Seller agrees to operate the Facility in parallel with Buyer's system and to deliver Buyer's Entitlement at the Delivery Point and at the voltage level and power factor not lower than [0.85], as specified in Appendix C. Unless otherwise requested by Buyer, Seller's Facility must be capable of operating at a power factor as specified in the Distribution Code at the point of delivery to Buyer.

2.11 Synchronization. Seller shall notify in writing Buyer and Buyer at least thirty (30) days prior to synchronizing or operating Seller's generators at the Facility for the first time in parallel with the Buyer's grid system, and coordinate such commencement of operation with Buyer at this first time and at future times that it resynchronizes or begins again to operate after a cessation of operation in parallel with the Buyer system.

2.12 Standards. Seller and Buyer shall comply with all regulations, including but not limited to, the Distribution Code, the Metering Code and all other relevant codes, rules, standards, procedures, and licenses applicable to the Parties.

2.13 Commercial Operations Date: At least six (6) and twelve (12) months prior to the Commercial Operations Date set forth in Appendix B, Seller shall officially inform the Buyer if the Commercial Operations Date needs to be extended, to which proposal the Parties shall attempt to agree and cooperate, which consent to reasonable extension Buyer shall not unreasonably withhold.

ARTICLE 3. CONNECTION, METERING, OPERATION

3.1 Delivery Point Responsibility. Seller shall make all arrangements at its own expense necessary to transmit and deliver Buyer's Entitlement to Buyer at the Delivery Point. Buyer shall cooperate with Seller in these arrangements.

3.2 Connection. Seller at its sole expense shall design, purchase, construct, operate and maintain Seller-owned connection facilities to connect the Facility to the distribution system, in compliance with the Distribution Code and applicable regulations of the Regulator, and if necessary shall pay for upgrading of metering at the distribution network substation to monitor bi-directional real and reactive power on the distribution line to which the Facility connects, as set forth in Appendix C. Buyer shall have the right to review the design as to the adequacy of the protective apparatus provided. The Seller shall be notified of the results of such review by Buyer in writing within thirty (30) days of Buyer's receipt of all specifications related to the proposed design. Any flaws perceived by Buyer in the proposed design shall be

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described in the written notice. Any additions or modifications required by Buyer, consistent with the Distribution Code, shall be incorporated by Seller.

3.3 Buyer's Obligation to Allow Connection. Buyer shall allow Seller to connect the Facility to the Buyer's distribution system, provided that Seller has met all requirements of Buyer as specified in this Article 3. Buyer shall respond to Seller's written request for connection to Buyer's distribution system within thirty (30) days from the date of receipt of such request. Buyer and Seller shall cooperate during the testing of the Seller's connection facilities.

3.4 Connection Standards. The Distribution Code shall apply to the installation and to the Operation of all of Seller's and Buyer's equipment and to the connection.

3.5 Connection Compliance. Upon reasonable prior notice, either Party has the right to inspect the other Party's connection equipment to ensure compliance with the Distribution Code. Such access shall not interfere with the other Party's normal business operations. If, in the opinion of either Party, the other Party's connection equipment is not being so operated and maintained, that Party shall notify the other Party of any such discrepancies which the Party responsible shall correct promptly.

3.6 Induction Generators. If Seller's Facility includes an induction-type generator(s), Seller shall provide individual power factor correction capacitors for each such generator. Such capacitors shall be switched on and off simultaneously with each of the associated induction-type generator(s) of the Facility. The KVAR rating of such capacitors shall be the highest standard value which will not exceed such generators' no-load KVAR requirement. Seller shall pay Buyer at the regulated retail tariff for the appropriate voltage level for the cost for all energy consumed from Buyer to excite the induction generators. Such payment shall be made as provided in Article 4.

3.7 Metering. Seller shall own and maintain the primary and secondary metering equipment employed for purposes of measurement and billing under this AGREEMENT. Metering and telemetering equipment shall comply with the Metering Code and applicable regulations of the Regulator, be capable of registering and recording the instantaneous and bidirectional transfer of power, kWh and KVArh, and capable of transmitting such data to such location(s) as may be specified by Buyer. The metering equipment shall be sealable and have mass storage and recording capability. Seller shall provide a suitable location for the metering and telemetering equipment if the Connection Point is at the Facility.

3.8 Meter Reading. Buyer and Seller shall mutually read the meters on the final day of each month at a mutually agreed time, or each Party shall have access to remote metering data as of that date. Seller shall provide Buyer access to the Facility at all reasonable times upon reasonable prior notice for the purpose of reading or inspecting meters, examining the Operation of the Facility or other purposes reasonably related to performance under the terms of this AGREEMENT. Such access shall not interfere with Seller's normal business operations. All Buyer personnel shall follow all Facility safety and procedural rules while on the Facility premises.

3.9 Meter Accuracy. All metering equipment measuring the output of the Facility shall be tested at least annually, at Seller's expense, in accordance with the Metering Code. At any reasonable time, any Party may request a test of the accuracy of any metering equipment. Each Party shall bear the cost of a test requested by it. The results of meter calibrations or

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tests shall be available for examination by the Parties at all reasonable times. If, at any time, any metering equipment is found to be inaccurate by more than the deviation tolerance specified by the Metering Code then in effect, Seller shall cause such metering equipment to be made accurate or replaced as soon as possible. Each Party shall be given reasonable advance notice of and have the right to be present at the breaking of the seals, testing, calibration and sealing of meters. If any Party believes that there has been a meter failure or stoppage, it shall immediately notify the other Party. The Party owning the meters will then investigate and take corrective action if necessary.

3.10 Meter Calibration. Testing and calibration of meters, and any verification of meter accuracy, shall be performed pursuant to the Metering Code by a qualified independent third party. Calibration shall occur before use of the meters to first record the output of the Facility. All meters shall be caused to be sealed and locked by Seller alter calibration, with Buyer allowed to witness this process.

3.11 Transfer of Title to Power. At the Delivery Point, electric energy, and legal title to same, shall be deemed to be transferred from Seller and delivered to possession of Buyer. At such point, Buyer shall be in exclusive control and possession of such electric energy and shall be solely responsible for same. Such electric energy transferred shall be by alternating current 3 phase, 50 Hz nominal frequency, at the voltage specified in Appendix C.

3.12 Operation. The Facility shall be operated by Seller in a manner consistent with the Distribution Code, all applicable codes, and Good Utility Practice.

3.13 Connection Liability. Each Party shall accept all liability and release from, and indemnify the other Party against, any liability for faults or damage to connection facilities, the electric system and the public, as a result of the Operation of the Party's connection equipment.

ARTICLE 4. BILLING AND PAYMENT

4.1 Billing. The Parties shall mutually read Facility meters or remote metering data on the final day of each month at an agreed time for determination of the electric energy delivered to and accepted by Buyer under the terms of this AGREEMENT during such month, and Seller shall record such reading(s), and consistent with regulations of the Ministry shall supply these meter values and an invoice based on such values, including the calculation of any distribution fees, if any, for which the Seller may be liable hereunder, to Buyer in written form (or by fax with following delivered or mailed copy) within ten (10) working days following each such reading.

4.2 Payment.

4.3(1) Buyer shall pay Seller any and all amounts due for the delivered Buyer's Entitlement on or before the Due Date, pursuant to the rates and subject to the terms set forth in Appendix A, which governs the applicable rate for payment for all power delivered under this AGREEMENT. Any undisputed amounts unpaid after the Due Date shall bear interest payable to Seller by Buyer at the Prime Rate compounded on a monthly basis for each month or part thereof alter the Due Date that any such amount remains unpaid.

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(2) A failure of Buyer to mutually read Facility meters pursuant to subclause 4.1 of this section shall not relieve Buyer of the obligation to pay Seller for the power delivered and accepted as provided herein.

(3) Seller shall pay Buyer the distribution fees, if any, as specified in Appendix D of this AGREEMENT.

(4) Seller shall pay Buyer at the regulated retail tariff for the appropriate voltage level for the cost for all energy consumed from Buyer, according to the regulations of this Article 4.

4.3 Estimation of Elements other than Quantity Sold. In the event that any data required for the purpose of determining amounts owed Seller or payment hereunder are unavailable when required, and the situation does not fall under the provisions of subclause 4.4, such unavailable data shall be estimated by Seller, subject to any required adjustment based upon actual data in the next subsequent payment months.

4.4 Alternative Quantity Data. To determine the amount of Buyer' s Entitlement delivered and accepted in any billing period, recordation of amounts, billing, and payment will be based on the first available of the following metering or estimation options, in descending order of applicability:

(1) The primary Facility meter measurement(s) when that meter for the period at issue satisfies the accuracy Standard in Article 33.10; or

(2) The Facility' s secondary meter measurement when that secondary meter is positioned to record the electric energy delivered and accepted, and when that meter satisfies the accuracy standard in Article 33.10;

(3) Where all meters fall to accurately register electric energy delivered and accepted, the average monthly data for the Facility from the same month in the prior Contract Year, if available, as reasonably adjusted for the particular billing period by any relevant available data affecting Facility generation regarding rainfall, stream flow, actual Facility fuel consumption, average heat rate, hours of operation, time of operation of generators, and/or native self-use of power output (collectively "Operating Variations") during the period of meter failure, shall be employed, if applicable, to estimate the amount of electric energy delivered and accepted. Where such data are not reliably available, the average monthly Facility electric energy delivered and accepted during the previous six (6) billing periods prior to meter failure (or fewer months if the Facility is less than six months from the Commercial Operations Date), as adjusted or normalized for outages or Operating Variations, shall be used to estimate energy delivered by the Facility for the billing period.

4.5 Dispute of Bill. Any Party may dispute in good faith may any claimed delivery or billing error, amount, or payment by written notification to the other Party within one (1) year of receipt of an invoice pursuant to Article 7, whether or not payment has been made by Buyer. If dispute resolution pursuant to Article 7 is in favor of Seller, Buyer shall promptly thereafter pay the disputed amount plus interest computed at the Prime Rate to Seller, compounded monthly, from the Due Date to the date payment is made. If dispute resolution is in favor of Buyer, Seller shall refund any payment previously received of the disputed amount

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plus interest at the Prime Rate, compounded monthly, from the date such payment was received to the date the refund is made. All such payments pursuant to this section shall be due within fifteen (15) days of the date of the decision of such dispute resolution pursuant to Article 7.

ARTICLE 5. FORCE MAJEURE

5.1 Force Majeure. For purposes of this AGREEMENT, the term "Force Majeure" shall mean any event, including but not limited to the following events, not within the reasonable control and not due to the failure, negligence or persistent disregard, of the Party whose performance is adversely affected or becomes impracticable, and who chooses to invoke Farce Majeure:

(1) Action or restraints affecting the performance of any Party under this AGREEEMENT by a court or public authority having or purporting to have jurisdiction;

(2) After the Commercial Operations Date, the failure by Seller after diligent and timely efforts, to obtain a necessary consent or approval from the Government of Viet Nam, its instrumentalities or divisions, or the Regulator;

(3) Any natural events, fire, explosion, flood, tidal wave, typhoon or other extreme atmospheric disturbances, epidemic, or earthquake;

(4) any other cause, whether or not similar thereto, beyond the reasonable control of, and without the fault or negligence of, the Party claiming Force Majeure;

(5) Civil disturbance, insurrection, rebellion, hostilities, public disorder or public disobedience, sabotage, riot, embargo, Blockade, quarantine, lockouts, acts of war or the public enemy whether or not war is declared;

(6) Nationalization, expropriation, or confiscation of the assets of Seller by any agency, authority or ministry of the Government of Viet Nam with authority with respect to the power sector.

5.2 Not Force Majeure Events. Any obligations of any Party which arose before the occurrence of the Force Majeure event causing non-performance shall not be excused as a result of the occurrence of a Force Majeure event. The late payment of money owed or the damage or disability resulting from a failure of a Party to utilize Good Utility Practice is not excused by Force Majeure.

5.3 Force Majeure Protocol. No default as a result of an event of Force Majeure shall occur, provided that the adversely affected non-performing Party invoking Force Majeure shall:

(1) Provide prompt notice in writing to the other Party and Lenders of the occurrence of the Force Majeure event and the choice to invoke Force Majeure, giving an estimation of the event's expected duration and the probable impact an the performance of its obligations hereunder, and submitting good and satisfactory evidence of the existence of the Force Majeure event;

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(2) Exercise all reasonable efforts to continue to perform its obligations hereunder;

(3) Expeditiously take or initiate action to correct or cure the Force Majeure and periodically submit good and satisfactory evidence that it is making all reasonable efforts to correct or cure the Force Majeure;

(4) Exercise all reasonable efforts to mitigate or limit damages to the other Party, to the extent such action will not adversely affect its own interests; and

(5) Provide prompt notice to the other Party and Lenders of the cessation of the Force Majeure.

5.4 Force Majeure Effect. If a Party is rendered wholly or partly unable to perform its duties and obligations under this AGREEMENT because of a Force Majeure event, that Party shall be temporarily excused to the extent necessary from whatever performance is affected by the Force Majeure event to the extent so affected.

5.5 Force Majeure Duration. Notwithstanding the foregoing, if a Party is prevented from substantially performing its obligations under this AGREEMENT for a period of one (1) year due to the occurrence of a Force Majeure event, the other Party may elect to terminate the AGREEMENT by sixty (60) days written notice given any time thereafter to the nonperforming Party, unless substantial performance is resumed prior to the expiration of such sixty (60) day period; provided that the Buyer shall not elect to terminate the AGREEMENT under this part due to a Force Majeure event described in Article 5 subclause 5.1(2) or (6).

ARTICLE 6. TERM, DEFAULT AND TERMINATION

6.1 Term. As of the date and when signed below by the Parties, this AGREEMENT shall commence and, subject to the termination provisions set forth in this AGREEMENT, shall continue for the term of twenty (20) years, measured from the Commercial Operations Date. Notwithstanding the foregoing, the applicable provisions of this AGREEMENT shall remain in effect after termination hereof to the extent necessary to provide for final billings, billing adjustments, payments, and effectuation of all rights hereunder.

6.2 Default by Seller. Seller shall be deemed to be in default under this AGREEMENT, and Buyer shall have the options set forth in this section for the non-defaulting party, if Seller commits each or any of the following Events of Default, including:

(1) Seller fails to complete, abandons, or cancels construction of the Facility, or does not achieve the Commercial Operations Date as provided in Appendix B within three (3) months of such date, unless such failure is attributable to Force Majeure, the actions or inactions of Buyer, or attributable primarily to the non-issuance of government permits where the Seller has timely complied with all legal requirements to obtain such permits.

(2) The adjudged bankruptcy, dissolution, or liquidation of Seller.

(3) The Seller fails to perform or observe any of its covenants, terms, conditions, or provisions of this AGREEMENT for a period extending longer than sixty (60) days after written notice of such failure is given to the Seller and its Lenders, if

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any, by Buyer. If, however, such failure cannot reasonably be remedied within such sixty (60) day period, the Seller or its Lenders shall be allowed a reasonable period of time up to one (1) year after such written notice, to accomplish such remedy provided that efforts to accomplish the remedy commence within such initial sixty (60) day period and continue to attempt to complete such remedy as quickly as possible, unless otherwise extended by the provisions of Article 5. It shall not be an Event of Default if such failure of Seller is substantially caused by an action or inaction of Buyer.

(4) Without reasonable excuse, the failure of Seller to make an undisputed payment under the AGREEMENT when due and nonpayment continues for more than ninety (90) days.

(5) Seller contests and denies the enforceability of this AGREEMENT or part of this AGREEMENT.

(6) Material violation of the representations and warranties made by Seller in Article 10.

6.3 Default by Buyer. Buyer shall be deemed to be in default under this AGREEMENT, and Seller shall have the options set forth in this section for the non-defaulting Party, if Buyer commits each or any of the following Events of Default, including:

(1) The adjudged bankruptcy, dissolution, or liquidation of Buyer.

(2) The Buyer fails to perform or observe any of its covenants, terms, conditions, or provisions of this AGREEMENT for a period extending longer than sixty (60) days alter written notice of such failure is given to the Buyer and its Lenders, if any, by Seller. If, however, such failure cannot reasonably be remedied within such sixty (60) day period, the Buyer or its Lenders shall be allowed a reasonable period of time up to one (1) year after such written notice, to accomplish such remedy provided that efforts to accomplish the remedy commence within such initial sixty (60) day period and continue to attempt to complete such remedy as quickly as possible, unless otherwise extended by the provisions of Article 5. It shall not be an Event of Default if such failure of Buyer is substantially caused by an action or inaction of Seller.

(3) Without reasonable excuse, the failure of Buyer to make an undisputed payment under the AGREEMENT when due and nonpayment continues for more than ninety (90) days.

(4) The compulsory expropriation, acquisition or nationalization of the material assets or equity of Buyer, Seller or the Facility by any instrumentality of the Government of Viet Nam, or the dissolution or reorganization of Buyer such that it or its successor cannot perform its obligations hereunder.

(5) Buyer contests and denies the enforceability of this AGREEMENT or part of this AGREEMENT.

(6) Material violation of the representations and warranties made by Buyer in Article 10.

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6.4 Default Procedure; Lenders' Rights; Cure.

(1) Upon the occurrence of an Event of Default, in each and every Case, a non-defaulting Party shall give written notice to the defaulting Party and its Lenders. The Parties and Lenders shall cooperate to resolve the Event of Default. The Lenders, if after such notice indicate in writing to the non-defaulting Party that they wish to attempt to cure the Event of Default, shall have the right to provide notice to the non-defaulting Party and step into the defaulting Party's obligations under this AGREEMENT, and be afforded a reasonable time under the circumstances to cure the Event of Default. The Lenders shall have the right to nominate and substitute third-party companies to cure the Event of Default, provided that such substitution shall not increase the financial burdens an the non-defaulting Party. The non-defaulting Party shall accept such step in and/or substitution of third parties by the defaulting Party's Lenders.

(2) In the Buyer's Event of Default set forth in subclause 6.3(3), Seller is entitled to suspend the provision of Buyer's Entitlement following a 5 (five) days advance notice to Buyer and shall not be liable to Buyer for damages caused by the suspension.

6.5 Termination. If the Event of Default is not cured as provided in the immediately preceding Articlesubclause 6.4, the non-defaulting Party and may pursue any remedies provided for in this AGREEMENT or under law, including the right to seek damages for breach of this AGREEMENT, and may terminate this AGREEMENT by giving a written notice of termination to the defaulting Party. If termination is chosen by the non-defaulting Party pursuant to the terms and conditions of this Article, then the Parties shall have no further obligations, except as set forth in subclause 6.1 hereof.

6.6 Limitation of Liability. Neither Buyer nor Seller, nor their respective officers, directors, agents, employees, owners, Lenders, subsidiaries, successors, assignees, or affiliates shall be liable or responsible to the other Party or its officers, directors, agents, employees, owners, Lenders, subsidiaries, successors, assignees, or affiliates, for incidental, indirect or consequential liability or payments of any nature, connected with or resulting from performance or non-performance of obligations pursuant to this AGREEMENT, including, without limitation, claims for lost revenues or profits. Only direct damages are compensable.

ARTICLE 7. DISPUTE RESOLUTION

(a)7.1 Informal Resolution. The Parties acknowledge that a dispute may arise between the Parties regarding the applicability, interpretation, payment, or enforcement of this AGREEMENT. If any dispute arises among the Parties related to this AGREEMENT, the Party claiming the dispute shall notify the other Party in writing of the dispute, and the Parties shall attempt informally to settle such dispute in good faith within a period of sixty (60) days thereafter; provided that disputes about the payment of money shall be attempted to be settled informally within fifteen (15) days. After such sixty (60) day or fifteen (15) day, respectively, informal effort, the Parties may engage in the dispute resolution procedures provided in part subclause 7.2(b) of this section, or seek any other remedy at law or equity. This dispute resolution mechanism is not applicable to disputes of a Party with third parties not directly arising under this AGREEMENT.

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(b)7.2 Referral to Regulator. If within the periods specified in subpart (a) subclause 7.1 a dispute is not resolved to the mutual satisfaction of the Parties, any Party involved in the dispute may refer the dispute in writing to the Regulator to mediate and resolve the dispute pursuant to the dispute resolution regulations or procedure of the Regulator. The Parties shall abide by and act in accordance with the Regulator's written decision, pending a final legal or equitable resolution in the Economic Courts, if such appeal is taken. The Regulator shall have no liability to either Party for actions taken in its role to resolve disputes hereunder.

(c)7.3 Appeal to the Economic Court. If not satisfied with the Regulator's resolution, an affected Party may appeal to the Economic Court in Viet Nam.

ARTICLE 8. DELEGATION AND ASSIGNMENT, RESTRUCTURING

(a)8.1 Assignment; Delegation. This AGREEMENT shall survive for the benefit of and bind the respective successors, assigns, and delegates of the Parties. No assignment or delegation by Seller of any of its rights, duties, or obligations hereunder shall be made or become effective without the prior written consent of Buyer, which consent shall not be unreasonably withheld by Buyer or its successors in interest, except that without Buyer consent Seller may assign and/or delegate some or all of its rights and duties to Lenders for purposes of financing, obtaining equipment, or construction of the Facility. If the assignee of Seller's interests has an approximately comparable creditworthiness and facility operating competence, it shall be deemed a reasonable assignment of the AGREEMENT. The Party assigning rights or delegating duties shall notify promptly the other Party in writing of any assignment or delegation that it makes.

(b)8.2 Restructuring. The plans of the government are to transition the electric power sector to a more competitive electricity market, which could involve the unbundling, restructuring, and/or reorganization (such actions collectively referred to as "Restructuring") of the functions of Buyer and/or Buyer, and cause affected rights and/or obligations under this AGREEMENT to be transferred to successor entity(ies). Buyer represents and warrants that as part of any such Restructuring, it will cause any successor(s) assuming any or all of its power purchase or power distribution functions hereunder to fully assume in writing those obligations of Buyer under this AGREEMENT.

(c)8.3 Opt-Out Option. If and after Restructuring is implemented during the term of this AGREEMENT, and if allowed by government regulations, the Seller shall have the option, but not the Obligation, by one-hundred twenty (120) day advance notice as provided herein to Buyer and to the Regulator, to unilaterally opt-out of and avoid this AGREEMENT, so as to enable Seller to participate in the restructured power market under the rules applicable to such market.

ARTICLE 9. MISCELLANEOUS

(a)9.1 Modification. This AGREEMENT may not be modified or amended except in writing signed an behalf of both Parties by their duly authorized officers.

(b)9.2 Cooperation. It shall be Seller's obligation to take all necessary actions to satisfy all applicable legal requirements regarding the Facility. Buyer shall cooperate with Seller to obtain all necessary consents, permits, licenses and approvals from government authorities to site, obtain fuel(s), control necessary resources or rights, invest in, transmit and seil electric

18

energy, and own and operate the Facility, including but not limited to executing and delivering any additional documents or Instruments in recordable form, and any other reasonably necessary acts, to carry out the intent of the Parties hereto.

(c)9.3 Entire and Complete Agreement. This AGREEMENT constitutes the entire and complete final agreement between the Parties relating to the subject matter hereof, and all previous agreements, discussions, communications and correspondences with respect to the subject matter hereof are superseded by the execution of this AGREEMENT.

(d)9.4 Choice of Law. The interpretation and performance of this AGREEMENT shall be in accordance with and controlled by the laws of the government of Viet Nam.

(e)9.5 Waivers. There shall be no implied waivers under this AGREEMENT. The failure of any Party to require compliance with any provision of this AGREEMENT at any time shall not affect that Party's right to later enforce same. It is agreed that the express waiver by any Party of performance of any of the covenants or conditions of this AGREEMENT, or any breach thereof, shall not be held or deemed to be an implied waiver by that Party of any subsequent failure to perform the same or any other term or condition of this AGREEMENT, or any breach thereof.

(f)9.6 Severability. If any clause of this AGREEMENT is ruled invalid or unenforceable by a court of competent jurisdiction, it shall not affect the remainder of the AGREEMENT if it can be construed to effect its essential purpose without the invalid clause.

(g)9.7 No Interpretation of Headings. The headings in this AGREEMENT are descriptive only, and are not intended to affect the interpretation or meaning of the AGREEMENT, and accordingly are not meant to be construed as part of obligations of any Party hereunder.

(h)9.8 Notice. Any notice, invoice, or other communication which is required or permitted by this AGREEMENT, except as otherwise provided herein, shall clearly specify that it relates to this AGREEMENT, bearing the date of its creation, be in writing and delivered by personal service or fax with a subsequent copy mailed postage prepaid, properly addressed, as follows:

(1) In the case of Seller to: General Manager, _________________, ______________________,_______________, Viet Nam;

(2) In the case of Buyer to: General Manager, _________________, ______________________,_______________, Viet Nam.

(3) Another address or addressee for notice, including designation of Lenders, may be specified or substituted by a Party in the manner provided herein.

(4) Each notice, invoice or other communication which shall be mailed, delivered or transmitted in the manner described above shall be deemed sufficiently given and received for all purposes at such time as it is delivered to the addressee or at such time as delivery is refused by the addressee upon presentation.

(5) Whenever a notice or other communication is required hereunder to be provided to a Party, a copy of each such notice shall be provided to Lenders, if any, by similar mode of transmission at the address provided in writing by a Party to the other Party regarding such Lenders.

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(i)9.9 Confidentiality. Buyer agrees to keep confidential any Facility technical data contained in the Appendices to the AGREEMENT, unless previously released by the Seller or the Regulator.

ARTICLE 10. REPRESENTATIONS AND WARRANTIES

In addition to the provisions of Article 8, each Party represents and warrants to the other that:

(1) it is legally established to do business in Viet Nam;

(2) the execution and performance of this AGREEMENT is duly authorized as required by its enabling authority or its by- laws, and does not conflict with any law, rules, regulations or requirements affecting or binding that Party;

(3) there is no legal or administrative action pending that prohibits or impairs the Party from performing under the AGREEMENT or might materially and adversely affect the Party's ability to perform its obligations under this AGREEMENT;

(4) this AGREEMENT constitutes a valid, legal and binding obligation of the Party in accordance with the terms hereof;

(5) the execution, delivery and performance by the Party of this AGREEMENT will not contravene any provision of, or constitute a material default under, any other agreement or instrument to which it is a party or by which it is bound.

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This AGREEMENT is made intoexecuted in nine (9) copies originalseach of which has the same validity, . Each Party will keep four (4) copies originals each being for the Buyer and the Seller, and one (1) original being for the Regulator to be delivered by the Seller. is responsible to send one copy to ERAV.

BUYER SELLER

By: ________________________________ (authorized signature)

By: ________________________________ (authorized signature)

Print Name: __________________________ Print Name: __________________________

Title: ________________________________ Title: ________________________________

Buyer's Name: ________________________ Seller's Name: ________________________

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APPENDIX A

RATES FOR DELIVERY OF BUYER'S ENTITLEMENT

[to be published by Regulatory annually -- version current at time of contract execution will be attached]Seller shall sell and Buyer shall purchase Buyer's Entitlement at the regulated Feed-In Tariff, as published by the Regulator, as follows:

1. Applicable Feed-In Tariff.

(i) During the period commencing on the date on which one (1) or more of the Turbines in the Facility commence to reliably produce and deliver Buyer's Entitlement until the date on which the complete Facility, including all Turbines, commences to reliably produce and deliver Buyer's Entitlement, the delivered Buyer's Entitlement during this period shall be paid at the Feed-In Tariff approved by the Regulator for the period in which the first Turbine commenced operation.

(ii) During the period commencing on the date on which the complete Facility, including all Turbines, commences to reliably produce and deliver Buyer's Entitlement and continuing thereafter during the remainder of the Term of the AGREEMENT, the delivered Buyer's Entitlement during this period shall be paid at the Feed-in Tariff approved by the Regulator for the period in which the complete Facility commenced operation, and adjusted in accordance with clause 2 of this Appendix A.

2. Indexation.

(i) [Twenty] ([20%]) percent of the Feed-In Tariff, shall be adjusted annually according to the Vietnamese consumer price index as published by the General Statistics Office, if the index is not available or if the Parties agree otherwise, then another mutually agreed index. The adjustable portion of the Feed-In Tariff shall be adjusted for the first time on the first day of the second Contract Year and after that once a year on each anniversary of that date. The effective value of the index on January 1 of the first Contract Year shall be considered to be the reference index.

(ii) The applicable rate for purchase and sale of electric energy applicable to this AGREEMENT in any Contract Year except the first Contract Year shall be calculated as follows:

ARy = FFIT * [320%] * (CPIy / CPIr) + FFIT * (1-[320%])

where:

FFIT = Feed-In Tariff approved by the Regulator for the year in which the entire Facility commences operation (in VND / kWh)

ARy = Applicable rate for payment of Buyer's Entitlement in Contract Year y

[20%] = Adjustable portion of Feed-In Tariff

CPIr = Reference Consumer Price Index

CPIy = Consumer Price Index as applicable for Contract Year y

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3. Taxes. In addition to the amounts otherwise payable by Buyer in accordance with this Appendix A, Buyer shall pay all taxes, but excluding in all events taxes based on or measured by net income, which are imposed by any taxing authority arising out of or with respect to the purchase or sale of Buyer's Entitlement (regardless of whether such taxes are imposed on Buyer or Seller), together with any interest, penalties or additions to tax payable with respect to such taxes.

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APPENDIX B

DESCRIPTION OF SELLER'S FACILITY

[to be provided individually for each project]

PART A: GENERAL ELEMENTS

Name of Facility: _________________________________________________

Location of Facility: _________________________________________________

Nameplate Rating: ______________________________________________kW

Number of Turbines: _________________________________________________

Design Operating Characteristics : _____________________________________________

Cut-off Wind Speed: ____________________________________________m/sec

Capacity to Sell to Buyer: Min ________________ kW; Max _________________ kW

Capacity Consumed by Seller: Min ________________ kW; Max _________________ kW

CAPACITY SOLD TO LOCAL DISTRIBUTION ENTITY: MIN_____KW; MAX____KW

Expected Annual Production: _____________________________________________ kWh

Date of Planned Completed Construction of Facility:____________________________

Voltage Delivered to Buyer: _____________________________________________Volts

Buyer Connection Point: _________________________________________________

Location of Metering Equipment: ______________________________________________

Date of Planned Commercial Operations Date: __________________________________

PART B: TECHNOLOGY-SPECIFIC OPERATING CHARACTERISTICS

TYPE OF FUEL: ____________________________________________________________

Type of Power Cogeneration Technology: _______________________________________

Design Operating Characteristics : _____________________________________________

FLOW OR FUEL QUANTITY/MONTH: _________________________________________

FUEL STORAGE (RESERVOIR CAPACITY OF STORAGE): _______________________

FLOW/FUEL INTERRUPTION PERIOD: ________________________________________

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APPENDIX C

INTERCONNECTION REQUIREMENTS

[to be provided individually for each project depending on project characteristics and technologies, including one-line diagram of connection facilities, and list of metering system characteristics, voltage]

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APPENDIX D

DISTRIBUTION FEES

[Not applicable to most NSPPAs]

[If any, current applicable version of distribution fees, as approved by the Regulator, for Buyer's distribution services for the Facility, applicable at time of execution of the AGREEMENT.]

4890S11/FICHT-5530494-v1

Annex 3 Explanatory Notes to

Standard Power Purchase Agree-ment for Purchase of Electric un-

der a Feed-In Tariff

4890S11/FICHT-5531269-v1 I

Table of Contents

Introduction 1

Article 1: Definitions 1

Article 2: Delivery, Sale, and Purchase of Entitlement 2

Article 3: Connection, Metering, Operation 3

Article 4: Billing and Payment 4

Article 5: Force Majeure 5

Article 6: Term, Default and Termination 5

Article 7: Dispute Resolution 6

Article 8: Delegation and Assignment, Restructuring 6

Article 9: Miscellaneous 7

Article 10: Representations and Warranties 7

Appendices 7

ATTACHMENT: Draft Non-Negotiable Standardized Power Purchase Agreement for Purchase of Electric Energy under a Feed-In Tariff

4890S11/FICHT-5531269-v1 1

Introduction This documents provides explanatory notes to the draft for a Non-Negotiable Standardized Power Purchase Agreement for Purchase of Electric Energy under a Feed-In Tariff. The draft is based on an unauthorized English translation of the current Standardized Power Purchase Agreement (PPA) for Renewable Energy Small Power Projects which applies to contracts between independent power producers utilizing renewable energy sources and distribution companies. The relationship between independent power producers utilizing wind energy sources and distribution companies requires a different PPA, because of the different type of tariff applicable (feed-in tariff for small wind power plants and avoided cost tariff for renewable energy small power projects). The technical differences in energy production also require specific regulations. Applicability. This Non-Negotiable Standardized Power Purchase Agreement for Purchase of Electric Energy under a Feed-In Tariff is intended to be applied to all new small wind power plants with total installed capacity of up to 30 MW. At the same time, the PPA for Renewable Energy Small Power Projects will no longer apply to small wind power plants. For wind power plants with more than 30 MW installed capacity the Standardized PPA for Small Wind Power Plants may serve as a basis, but would need to be amended to consider specific characteristics of the larger plant. Larger wind power plants may have a different cost structure, so that it may not be justified to apply a Feed-In Tariff derived from the costs of smaller wind power plants; furthermore, the connection of larger wind power plants may have a stronger impact on the distribution grid and therefore needs to be specifically regulated; the amount of the energy produced by a larger wind power plant in relation to the total energy sold by the distribution company may also have an impact on the contractual relation between the wind power plant and the distribution company. Parties to the Agreement. The Standardized Power Purchase Agreement for Small Wind Power Plants applies to the sale of electrical energy from an independent wind power producer to a distribution company which has its own distribution network and is licensed to sell electricity to end-users. The sale to a company without its own distribution network would require a separate interconnection agreement. In view of the on-going electricity sector restructuring, the PPA includes provisions on the effects of restructuring, including changes to the rights and functions of the distribution companies.

Article 1: Definitions This article provides definitions for relevant terms used in the PPA. These definitions are necessary for the avoidance of doubt when interpreting the

4890S11/FICHT-5531269-v1 2

terms. Defined terms are capitalized throughout the PPA to indicate that more information is provided under "Definitions". Definitions specific to the PPA for Small Wind Power include the following: • "Small Wind Power Plant" refers to a wind power plant up to 30 MW

installed capacity which qualifies for the Feed-In Tariff. The standardized PPA applies to any of them.

• "Facility" refers to the small wind power plant of the wind power producer who signs a PPA with a distribution company. The facility may comprise a single turbine or a wind farm with several turbines.

• "Turbine" refers to a single turbine which may represent the entire facility or part of it.

• "Feed-In Tariff" refers to the tariff applicable to any qualifying small wind power plant that starts operation in a specific year; this tariff as approved by the Regulator applies to the sale and purchase of wind energy irrespective of the time-of-day or season.

Article 2: Delivery, Sale, and Purchase of Entitlement

This article specifies the amount of energy that the wind power producer ("Seller") agrees to deliver and the distribution company ("Buyer") agrees to accept (defined as "Buyer's Entitlement"). Amount of energy. The Buyer is obliged to purchase all the energy delivered by the Seller, and the Seller is obliged to sell all the energy produced to the Buyer. Sales to a third party, e.g. for rural electrification, are not explicitly considered. In consideration of the intermittent nature of wind, the amount of energy is not fixed in absolute terms. Instead, the amount is variable, as generated at any given moment. As a consequence, the Seller does not have to pay a penalty if it cannot deliver energy due to the wind conditions or any other cause outside of its control; nor is the Seller liable to the Buyer for damages resulting thereof. The article also defines the extent to which the Seller is allowed to interrupt, reduce or refuse to deliver energy to the Buyer without being in breach of its obligations. It defines as well the extent to which the Buyer is allowed not to purchase the delivered energy to the Buyer without being in breach of its obligations. If the Buyer does not purchase the delivered energy for any other than the listed reasons, it nevertheless has the obligation to pay for the energy that could have been delivered ("Must Take" or purchase obligation). Environmental attributes. The Buyer has the right to any environmental credits or attributes earned by the wind power plant. In this way, the Buyer may be partially compensated for the higher feed-in tariff it has to pay for the wind energy.

4890S11/FICHT-5531269-v1 3

If the environmental credit are to be collected by another institution, such as the Vietnam Environmental Protection Fund or the Renewable Energy Finance and Subsidy Fund, the PPA would need to be adjusted accordingly. Forecasting. The article also sets out the provisions for forecasting of the wind power plant's energy generation. Due to the intermittent nature of wind, there is a high level of uncertainty associated with any forecasting. Therefore forecasting obligations of the Seller are limited to annual updates of the initial assumptions on electricity generation for each month of the year which was the basis for the Seller's feasibility study, and penalties for deviation from the forecast amounts are explicitly excluded. Reporting. In order to assist the distribution company or the dispatcher in their energy scheduling, the PPA includes the obligation of the Seller to monitor relevant parameters, such as wind velocity, wind direction and temperature, and pass the measurements on to the Buyer. Reporting obligations may be adjusted to requirements of the Regulator for monitoring purposes. Outages. Seller and Buyer are obliged to cooperate to minimize the periods during which the wind power plant does not generate electricity or the distribution company does not accept the delivered energy. This includes mutual consent on the periods of scheduled outages for maintenance and repair, which – in the interest of both Seller and Buyer – should be performed during seasonal low-power-demand periods or low-wind resource periods, and prompt information on unscheduled outages. Unscheduled (forced) outages include any unplanned component failure or other conditions that make it necessary to remove the turbines from service immediately, such as wind speeds above the cut-off wind speed of the turbines. The cut-off wind speed is specified in Appendix B to the PPA. Forced outages for reasons which are beyond the Seller's control do not count as breach of contract.

Article 3: Connection, Metering, Operation This article regulates the connection of the wind power plant to the distribution company's grid as well as the metering of the delivered and purchased energy. Cost of connection. The PPA stipulates that the Seller is responsible for connection to the distribution grid at its own expense. Subsidies are not considered, as it is assumed that there are sufficient locations for new wind power projects within short distance to the grid, and thus with affordable connection costs. Connection obligation. According to this article, the distribution company is obliged to connect the wind power plant to its distribution system, subject to conditions to be met by the wind power producer. Rights and obligations of both parties with regard to the connection are listed; e.g. the distribution company has the right to inspect the design of the connection facilities and

4890S11/FICHT-5531269-v1 4

request changes. In order to prevent delays a time limit is given for the distribution company's response to the wind power producer's request for connection. Metering. The metered electricity forms the basis for payments under the PPA; therefore it is in the interest of Seller and Buyer to regularly calibrate the meters and check them for accuracy. The article describes where the meters will be located, who is responsible for maintaining them, who will read the meters and the frequency of meter reading.

Article 4: Billing and Payment This article states the price to be paid for the wind energy (with reference to the more detailed description in Appendix A) and describes the procedures for billing and payment. Feed-In Tariff. Since the standardized PPA is valid for all new qualifying wind power plants, the price for the wind energy is non-negotiable. The Seller does not have the right to choose between the Avoided Cost Tariff applicable to Renewable Energy Small Power Plants and the Feed-In Tariff for wind energy. The Buyer has to pay the Feed-In Tariff for wind energy as approved by the Regulator. The Feed-In Tariff for wind energy is an energy price expressed in VND/kWh, irrespective of time-of-day or season. The Feed-In-Tariff is determined for each year over a defined period, and the tariff applicable to the specific wind power plant is the one set by the Regulator for the year in which the wind power plant goes into operation. This tariff is then valid over the entire term of the PPA, except for the escalation of its adjustable portion. Escalation. The adjustable portion (proposed at 20% of the Feed-In Tariff) is equivalent to the share of operation and maintenance expenses in total lifecycle costs of a small wind power plant. Since O&M costs – in contrast to the on-off capital costs – are subject to annual price increases, the adjustable portion of the Feed-In Tariff is increased annually in line with local inflation. Appendix A describes the procedure for inflation adjustment in more detail. Note that there is no adjustment for exchange rate variation; the exchange rate risk associated with imported equipment is expected to be borne by the wind power producer. Startup Issues. Often the first turbines installed on a project are able to begin delivering energy before the entire facility is completed. The PPA allows the Seller to sell the energy from the first turbines before the entire facility is completed. As an incentive for early completion this energy is remunerated at the Feed-In Tariff set by the Regulator for the year in which the first turbine starts to operate. Once the entire wind farm is completed, the rate to be paid by the Buyer for the entire energy produced is the Feed-In Tariff set by the Regulator for the year in which the last turbine starts to operate. Thus, the actual date when the last turbine goes into operation is

4890S11/FICHT-5531269-v1 5

decisive for the determination of the applicable tariff, regardless whether the commercial operations date specified in Appendix B of the PPA is met or delayed. After the start of commercial operation of the entire wind farm, the energy generated from the first turbines is remunerated at the same rate as the energy from the last turbine, since the meter measuring amount of energy to be billed does not differentiate between the generation of individual turbines. Billing. The billing procedures outline how often (monthly) and how long after meter reading (ten days) the Seller will invoice the Buyer, and when the payment is due (within 15 days). Buyer or Seller may dispute an invoice. Dispute settlement is described in Article 7 on Dispute Resolution. Interest charges accrue on unpaid invoices. During a dispute or when the Buyer does not pay an undisputed amount for up to three months the Seller is not entitled to suspend the electricity supply to the Buyer. This is regulated in Article 6 on Term, Default and Termination.

Article 5: Force Majeure This article lists all events that are beyond the control of the Seller or the Buyer and that may result in stopping the operation of the wind power plant or not allowing the Buyer to accept the delivered energy. Force majeure events include, among others, political events and atypical natural events. Tornados and severe storms are events of specific importance for wind power plants. The maximum wind speed which the specific wind power plant is designed to withstand before stopping operation (cut-off wind speed) is specified in Appendix B; any wind speed beyond the cut-off speed would be considered force majeure. The article on Force Majeure also describes the process for reporting a force majeure event, acceptance by the other party, and the options to cure the event. If the event cannot be cured, then the agreement may be terminated.

Article 6: Term, Default and Termination This article contains clauses regarding the duration of the agreement, the actions of each party that are considered a breach of the agreement (default) and the consequences of a default. Term. The PPA for Small Wind Power Plantshas a duration of twenty years, equivalent to the economic lifetime of the wind power plant. There are no provisions for extension of the agreement, considering the duration of the Feed-In-Tariff scheme and the pending restructuring of the electricity sector. Decommissioning. After the end of the agreement term, the wind power producer should remove all equipment and buildings, including foundations, and restore the land to its original condition at its own expense. It is recommended that such a provision is included in the land lease agreements for qualifying small wind power plants. The costs of the decommissioning

4890S11/FICHT-5531269-v1 6

should be paid from a Decommissioning Reserve Fund, to be established by the investor of the wind power plant over ten years and funded from the available cash flow. It is recommended that the obligation to establish such a Reserve Fund is included in the loan agreements. Default. Defaults include, among others, non-delivery and non acceptance of the delivered energy for reasons within the control of the parties, non-payment, bankruptcy, and failure to cure breaches of the agreement within the allowed cure period. Insufficient wind conditions and wind speed beyond the cut-off speed are beyond the control of the Seller and therefore the resulting non-delivery of energy cannot be considered as breach of the agreement. The cure provisions define the procedures and timeline to be followed by the Buyer and the Seller to resolve default events. Remedies include the compensation for damages resulting from breach of the agreement, according to Commercial Law. The liability for damage compensation is explicitly limited to direct damages. The PPA does not consider additional penalties for breach of the agreement, since they may render sale and purchase of wind energy unattractive to the parties. Non-payment of the delivered energy is not considered a default unless it continues for longer than three months. Only after three months the PPA gives the Seller the right to suspend the electricity supply, in addition to seeking other remedies or terminating the agreement. Termination of the agreement is the last resort to resolve any events of default.

Article 7: Dispute Resolution This article describes the procedures for dispute resolution and the associated timelines. If the dispute cannot be settled among the parties in good faith, the parties may refer the dispute to the Regulator. If it cannot be settled by the Regulator, the parties may then appeal to the Economic Court.

Article 8: Delegation and Assignment, Restructuring This article describes the conditions on which the Seller or the Buyer may assign the agreement to a third party or a successor company. Generally the consent of the other party is required. Specific provisions regulate the assignment of rights and obligations of a party in the case of sector restructuring, i.e. when the rights and obligations have to be transferred by law. In this case, the Seller has the option to terminate the agreement so as to participate in the restructured power market under new market rules.

4890S11/FICHT-5531269-v1 7

This opt-out option is subject to the condition that it is allowed by government regulations. The Consultant recommends not to allow such an option for the wind power plants operating under the Feed-In Tariff, because it cannot be justified that the wind power producer first benefits from the Feed-In Tariff and later from possibly higher market rates without any compensation to those parties which contributed to the funding of the Feed-In Tariff.

Article 9: Miscellaneous This article comprises miscellaneous clauses with necessary provisions for the execution of the agreement, such as governing law, obligation of the parties to cooperate in acquiring all necessary permits, communication between the parties, confidentiality etc.

Article 10: Representations and Warranties This article lists the assurances of the parties that certain statements about their legal and administrative condition are true and may be relied upon by the other party.

Appendices APPENDIX A. Rates for Delivery of Buyer's Entitlement This appendix describes the applicable rate for wind energy sale and purchase under the agreement and its annual escalation. See explanation above in Article 4: Billing and PaymentArticle 4: Billing and Payment. APPENDIX B. Description of Seller's Facility This appendix provides a detailed description of the wind power plant. It has to be prepared individually for each specific PPA. APPENDIX C. Connection Requirements This appendix provides details of the connection facilities which connect the wind power plant to the distribution system. It has to be prepared individually for each specific PPA.

APPENDIX D. Distribution Fees This appendix lists the distribution fees for the services of the distribution company to the wind power plant, if applicable to the specific PPA.

4890S11/FICHT-5530494-v1

Annex 4 Power Plant structure in Vietnam

Power generation by fuel type 2001-2008 Unit : GWh 2001 2002 2003 2004 2005 2006 2007 2008

Total generation 31137 36410 41275 46790 53647 61533 68699 75956

Hydropower 18170 18205 19004 17968 16432 19573 22698 25984Hoà Bình 8447 8167 8597 8405 8165 7701 9100 10140Thác Bà 401 401 371 380 335 322 324 475Tuyên Quang 64 1132Quảng Trị 260 254Vĩnh Sơn 215 218 270 217 184 331 260 361Sông Hinh 441 370 402 359 289 397 398 498Ialy 2975 3735 3394 3321 3034 3755 3413 3337Sê San 3 612 1130 1131Trị An 2179 1847 1987 1742 1504 1946 2038 1661Đa Nhim 1053 810 951 766 525 1033 1187 1244Thác Mơ 927 832 831 637 581 896 899 762Hàm Thuận 924 1112 1216 1054 838 1183 1186 824Đa Mi 400 468 708 558 494 682 630 497Cần Đơn 256 259 327 361 346Srokphumieng 32 252 241Se san 3A 7 345 400Đại Ninh 1145A Vương 168Thuỷ điện nhỏ 208 245 277 273 224 349 851 1368Coal TPP 3219 4871 7193 7274 9305 10668 11275 11405Phả Lại 2220 2274 2579 2202 2459 2937 2832 2586Phả Lai 2 1351 3202 3529 4299 4315 4198 4331Uông Bí 490 697 731 641 669 757 694 720Uông Bí 2 520 532Ninh Bình 509 549 681 633 689 794 729 752Na Dương 70 389 709 744 695Cao Ngạn 70 445 761Formosa 199 800 1086 1113 1028Oil TPP 3290 2999 2152 1744 2168 1581 2560 2208Thủ Đức 880 812 697 424 549 472 603 583Cần Thơ 236 206 193 177 128 128 137 94Cái Lân 27 81 66Amata 74 70 68 50 67 26 13 1Hiệp Phước 2100 1911 1194 1066 1424 955 1726 1464Add-on 400 2598 3578 4839 5540 6267 6905 7004

GT using gas 4527 6226 9006 14587 18843 21034 22237 25894Bà Rịa 1095 1396 1347 1381 1386 1310 1244 1331Phú Mỹ 2-1 1924 544 2741 3159 2411 3842 3625 3786Phú Mỹ 1 1006 3775 4298 4192 4593 4236 5135 5160Phú Mỹ 4 1059 1829 2026 1971 2170Phú Mỹ 3 166 4154 4442 4110 3883 5121Phú Mỹ 22 210 3719 4855 5004 4222Cà Mau 1+2 691 2994Nhơn Trạch 1 589Vê Đan 502 511 454 432 463 514 534 395Đạm Phú Mỹ 141 150 126GT using oil 1414 1187 163 250 446 221 544 183Bà Rịa 151 70 28 18 41 13 81 35Phú Mỹ 2-1 451 522 13 21 114 50 132 43Phú Mỹ 1 72 216 9 7 6 5 42 8Phú Mỹ 4 32 108 12 68 17Thủ Đức 275 199 64 17 35 32 70 17Cần Thơ 465 180 49 155 142 109 151 63Diesel 90 86 29 43 16 25 42 15Other 22 29 72 97 426 1023 2699 3263

BourBon 22 29 72 58 43 57 69 43Import from China 39 383 966 2630 3220

4890S11/FICHT-5463942-v1

Installed and available capacity 2008Power plants Unit Installed (MW) Available (MW)Total 15764 15125Hydropower plants 5498 5575Hoà Bình 8 1920 1960Thác Bà 3 120 120Tuyên Quang 3 342 342Quảng Trị 2 64 64Vĩnh Sơn 2 66 66Sông Hinh 2 70 70Ialy 4 720 720Sê San 3 2 260 260Trị An 4 400 440Đa Nhim 4 160 160Thác Mơ 2 150 150Hàm Thuận 2 300 300Đa Mi 2 175 175Đại Ninh 2 300 300A Vương 2 210 210Sê San 3A 2 108 108Cần Đơn 2 78 78Srokphumieng 2 55 52Coal TPP 1930 1880Phả Lại 1 4 440 400Phả Lại 2 2 600 600Uông Bí 2 105 105Uông Bí mở rộng 1 300 300Ninh Bình 4 100 100Na Dương 2 110 110Cao ngạn 2 115 110Formosa 1 160 155Oil TPP 627 613Thủ Đức 3 165 153Cần Thơ 1 35 33Cái Lân 6 39 39Amata 2 13 13Hiệp Phước 3 375 375GT 6681 6283Bà Rịa 8GT+2ST 399 322Phú Mỹ 21 4GT+2ST 982 880Phú Mỹ 1 3GT+1S 1138 1065Phú Mỹ 4 2GT+1S 468 440Thủ Đức 4 126 89Cần Thơ 4 150 136Phú Mỹ 3 2GT+1S 733 726Phú Mỹ 22 2GT+1S 733 715Cà Mau 1 2GT+1S 771 750Cà Mau 2 2GT+1S 771 750Nhơn Trạch 1 2GT 320 320VeDan 2 72 72Đạm Phú Mỹ 1 18 18Diesel and SHP 454 200Other 574 574Bourbon 2 24 24Import from China 550 550

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