FINAL DRAFT For internal discussion purposes only

January 7, 2013

RENEWABLE ENERGY FEED-IN TARIFF (REFIT)

FOR

NAMIBIA

______________________________________________________________________________

This DRAFT report is prepared by Nexant, Inc. under USAID Contract No. EPP-I-04-03-00007-00. The author’s views expressed in this document do not necessarily reflect the views of the United States Agency for International Development or the United States Government.

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Section 1 Introduction

1.1 REFIT PROGRAM OBJECTIVES

The findings in this Paper are based on the work conducted by Nexant, Inc., as part of the Technical Assistance requested by the Electricity Control Board (ECB) of Namibia and approved for support by the USAID under its Africa Infrastructure Program (AIP). The scope of this analysis is to propose Renewable Energy Feed-in Tariffs (REFITs) along with associated Regulations that would create an environment conducive to mobilizing Independent Private Producers (IPPs) and their investors into Namibia’s electricity sector.

Given that the nature of REFITs is to pre-commit to prices for projects that are yet to be identified, it is critical that the assumptions made leave little room for generalizations. This requires categorizing projects by resource base and size in order to capture the unique cost characteristics of the different technologies involved for each resource base (solar, wind, biomass and microhydro) and of the economies of scale in different sized projects. This is essential so as to (a) on one hand, adequately identify the tariff levels that would appropriately cover costs and provide an “acceptable return” to private developers, and (b) on the other, ensure that these levels are not excessive to the Offtaker NamPower, who has to pass it through to consumers. These tailor-designed tariffs aim to attract the private sector by proclaiming an “if you build it, we will buy it” policy for developers with Viable Projects, while allowing the country to integrate its RE resources into its energy mix in a least cost manner. The REFIT Program is, therefore, limited to projects less than 10MW1, so project costs can be generalized, while larger sized projects with wider cost variations from project to project, are left for competitive bidding.

A key feature of a successful REFIT Program is that it does not stop at listing the tariffs but has, as its integral part:

(a) Regulations whose intent is to define the rules of the game for areas beyond pricing that remain to be negotiated (i.e. assignment of connection costs, currency of payment, inflation adjustment methodology, etc.), thereby seeking to increase predictability; (b) Application and Project Screening Protocol with defined Pre-feasibility Study contents and a one-stop shop process reducing potential red tape; and (c) PPA Guidelines, thereby clarifying risk allocation parameters from the outset. 

This approach provides transparency of rules to entrepreneurs, who can be assured that if they structure a Viable Project it will have a predictable offtake price with predictable risk allocation arrangements with the Offtaker.

1 The premise of the REFIT Program is that it streamlines implementation of “less than 10MW” projects for which cost generalizations can be made so REFIT levels can be pre-set, while RE projects equal to and/or greater than 10MW are left for international competitive bidding (ICB,) as their costs cannot be generalized. Limiting the Program to a lesser range (say, less than 5MW) will render the Program less meaningful in its impact and miss out on streamlining the implementation of lower priced electricity projects in the higher end of the 10kw-10MW range, where there are economies of scale to be gained. However, prior to issuing the Regulations, ECB may make a determination to restrict the Program up to any level it chooses within the range of 10kw to 10MW, as this Report includes projects, as differentiated per technology and size, in this range.

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The enabling environment designed under such Program aims to usher in privately financed clean energy development projects and free up scarce government resources for other uses. This also helps small and medium enterprises (SMEs) expand, creates jobs, increases electrification, displaces high polluting diesel generation, and reduces greenhouse gas emissions.

Last but not least, while a REFIT Program dealing with small sized projects will not resolve the supply-demand gap issues of Namibia, it can go a long way in illustrating the principles of an enabling environment at work. These can subsequently be replicated for larger projects, thereby positively branding the country and the sector as receptive and progressive for investors and entrepreneurs alike, opening the way for private sector participation in larger projects.

1.2 SCOPE OF WORK

Namibia’s electricity market is structured as a vertically integrated Single Buyer model, with monopoly over power generation, transmission, trading, and some distribution functions. Currently, NamPower is the only generator of power in the country and will be the sole buyer from prospective IPPs. According to the Energy Supply Industry (ESI) Restructuring proposals, progress is expected to be made towards an investor oriented market as a Modified Single Buyer Model where IPPs will be able to sell directly to Regional Electricity Distributors (REDs) or contestable customers and do not have to necessarily sell to NamPower2.

Presently, the development of commercial private sector participation in RE is supported by ECB, as mandated in the Electricity Act of 2007 to issue conditional licenses in RE generation to potential IPPs. The regulator has been the recipient of several expressions of interest amongst investors in wind, biomass, solar photovoltaic (PV) and concentrated solar power (CSP) projects, for which conditional (and extendable) licenses of up to one year (at a time) have been issued. To date, there have been no IPPs to advance such license to full project development, construction, and operation stage. A key factor leading to this predicament is the deficiencies of the enabling environment which hinders private developers from undertaking the requisite upfront project development costs, given unpredictable elements critical to assessing project risk.

In view of the above, ECB has set the following Scope of Work (SOW) for Nexant:

(A) Develop a REFIT Program for solar, wind, biomass, and microhydro for small (under 10MW) projects, and inter alia:

i. Establish the rationale for an appropriate cost-plus-return structure that will adequately incentivize the private sector to develop these resources;

ii. Create a REFIT Pricing Model that will reflect the cost structure in Namibia and serve as a tool for policymakers to test various pricing scenarios and assumptions for the formulation of appropriate tariff and incentive policies;

iii. Develop associated Regulations that will support and facilitate implementation of the REFIT Program; and

2 ECB Annual Report 20113

iv. Identify appropriate Benchmarks from countries in the region to determine the position of such a REFIT Program in terms of its pricing level and comparative advantages stemming from the Regulatory framework that will be designed for its implementation.

(B) Upon completion of the REFIT, apply the REFITs on a select few small projects to set the Model Transaction with appropriate Model Power Purchase Agreement (PPA) and associated Regulations.

For these purposes, Nexant worked with ECB, NamPower, local construction companies, and others to collect local specific factor costs regarding construction and operation of solar, wind, and biomass resource based generation projects. Such data is compiled on the REFIT Pricing Model for Namibia (the Model) Nexant developed (Excel format) to calculate REFIT levels by resources type, project size, and on a cost plus “acceptable return” basis (Sections 4 - 6).

1.3 THE NAMIBIAN CONTEXT FOR REFITs

Sector OverviewNamibia has an estimated total installed capacity of 393MW which contrasts sharply with a reported peak demand of about 580MW (in 20113). With a population of 2.3 million spread over a surface4 area twice the size of the State of California, Namibia has one of the world’s lowest population density rates (2.8 people/ km2) and an electrification rate of merely 34 percent5.

A significant share of electricity is generated at the Ruacana hydropower station on the Kunene River which forms the shared border with Angola. This run-of-river facility has an estimated rated output of 249MW and has commissioned its fourth unit, increasing its generation capacity by 90MW. The plant is operated as a base-load resource during the rainy season (typically February-May) and as a peaking resource during the rest of the year. The second largest plant is a dry cooled coal-fired power station at Van Eck, with installed capacity of 120MW operated with coal imported entirely from South Africa and scheduled for rehabilitation. There is also Anxias, a relatively new short-term emergency generation heavy fuel oil facility with a capacity of 22.5MW. Lastly a 24MW diesel station at Paratus is used as an emergency stand-by power plant for the Erongo Region. Together, these power plants comprise the sum total of the domestic electricity supply and, as such, they are insufficient. Furthermore, these plants are old (all commissioned in the ‘70s) and have high operating and maintenance costs which place an excessive strain on the industry’s ability to retain earnings and self-finance its ability to offset its demand and supply-demand disparity.

According to the latest ECB6 data, Namibia imported 63.4% of its total electricity needs in 2011, of which the largest share of 31.4% from ZESA, followed closely by Eskom at 22% and ZESCO with 10% (all members of the Southern Africa Power Pool - SAPP7.) These imports, comprising

3 NamPower Annual Report 20114 Namibia has a surface of 824,269 km2 http://www.grnnet.gov.na/ 5 Development of Procurement Mechanisms for RE Resources in Namibia, REEEP, March 20116 ECB Annual Report 20117 ECB figures are different from those of NamPower, the exclusively licensed national utility for the import and export of power in Namibia. In the absence of additional data to reconcile the disparity, ECB’s assessment will

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almost two thirds of its electricity consumption, together with costly imports of coal and polluting diesel to complement domestic generation capacity, leave Namibia very vulnerable.

Table 1. Local and Imported Electricity TariffsLocal Generation vs. Imports (% Total) 2007/08 2008/09 2009/10 2010/11Namibian Generation 42% 40% 35% 37%Imports 58% 60% 65% 63%Cost (% Total)Namibian Generation 47% 22% 46% 35%Imports 53% 78% 54% 65%Average Price (c/kWh)Namibian Generation 0.27 0.32 0.43 0.36Imports 0.27 0.52 0.40 0.38

Source: ECB Annual Report 2011

Overall, the current generation capacity reveals severe constraints that inhibit the country’s ability to have an adequate and reliable supply of electricity to meet its present and forecasted demand. In response to an acute power deficit, estimated to reach 80MW in 2012 and 150MW by the end of 2013, mainly due to the growing needs of the mining sector8, NamPower initiated the Short-Term Critical Supply Project, as a listing of priorities to address the country’s immediate power supply shortage. Chief amongst them are:

the need to commission a base load power station by 2015-16, the renegotiation of existing PPAs with power utilities within the SAPP9, rehabilitation of existing power stations, and Renewable Energy (RE) integration in the overall energy supply mix.

Table 2. Namibia Load Forecast 2011-

200

300

400

500

600

700

800

900

1000

1100

1200

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

Peak

MW

Namibia Load Forecast

Low Medium High old forecast

Source: NamPower Annual Report 2011

prevail as the authoritative source for the purposes of this analysis.8 Skorpion Mine uses a large share of Namibia’s supply of electricity.9 NamPower has also commissioned the Caprivi Link Interconnector, a HVDC project intended to enable the trade of 300 MW capacity with Zambia and Zimbabwe, as well as other countries in the SAPP.

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Amid these supply shortage concerns and the growing demand for energy, the critically advantageous Power Purchase Agreements (PPAs) contracted with the national power utilities in the SAPP are going to run their course in the immediate future.

The anticipated renewal of the PPA with Eskom will provide NamPower with less favorable terms that would no longer offer firm supply of power. This is indicative of Namibia’s risk exposure associated with a continued dependence on electricity imports. At the same time, key domestic generation projects are faced with obstacles of their own: the Kudu gas-to-power project, with a contemplated 800MW generating capacity, is shelved due to failed negotiations with potential development partners and the 500MW mid-merit10 Baynes hydro power station requires negotiations with Angola which has shared rights over the river’s energy potential.

The White Paper11 on Energy Policy of 1998 sets forth six broad energy goals for the country: effective governance, security of supply, social uplift, investment and growth, economic competitiveness and efficiency, and sustainability. The Paper does acknowledge that the country needs to diversify its energy resources, emphasizing development of indigenous resources, and affirms “the potential use of renewable energy – including hydropower and wind turbines, and possibly large scale solar power plants in the longer term – for grid connected electricity can contribute to the policy goals of sustainability and also security of supply by virtue of diversification and the use of locally available renewable energy resources.”

In order to attain growth in domestic energy supply, Namibia will unequivocally need to tap into its RE potential and develop additional MW capacity from viable wind, solar, biomass and microhydro power projects. However, it is important to recognize that the country’s advances in the development of RE technologies will need to be equally matched by the addition of base-load capacity that contribute to the system reliability and ultimately to the security of supply.

The Case for REFITs in NamibiaAvailability of RE resources alone will not suffice or guarantee the effective integration of RE technologies in the power system of Namibia. As such, the REFIT Program will mandate technical, commercial, financial, economic, environmental, regulatory, legal, and other relevant feasibility prerequisites that prospective IPPs must demonstrate in advance of developing RE resource based power projects.

The purpose of this analysis is to evaluate the practical potential for grid connected small-scale RE technologies that would benefit from a REFIT Program in Namibia. Such a Program is intended for the application of up to 10MW power projects. The main considerations reviewed here are qualitative and quantitative parameters pertaining to the following:i) identified resource potential for small scale projects for each of the RE resource bases,

and ii) proximity of known potential project locations to NamPower’s existing transmission and

distribution networks (Annex 1 - note that proximity is not sufficient to guarantee

10 A mid merit power plant is operated 24 hours but at a varying output to follow the demand system.11 Developed by the Energy Policy Committee of the Ministry of Mines and Energy, Namibia 1998.

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technical feasibility, as grid connection needs to be studied on a case-by-case basis to determine whether the local grid can support the proposed project.)

Assessment of Feasibility for Microhydro 12 REFITs Assessment of available data on potential small scale hydro power sites in Namibia helps determine whether the country has a sufficient base for hydro potential of up to 10MW that has economic proximity to the grid to justify commercial development.

Namibia is the most arid country in sub-Saharan Africa with over 50 percent of its surface covered by desert and arid surfaces, and a mean annual rainfall of approximately 270 mm (11 in). There is a wide regional variation in annual rainfall, from less than 20 mm in the Western Namibia and coastal zones to more than 700 mm at the Eastern end of the Caprivi Strip, but only 5 percent of the country receives more than 500 mm (20 in).

Table 3. Annual rainfall distribution and climatic classification in NamibiaRainfall (mm) Classification Percentage of

land surface<100 Desert 22

101-300 Arid 33301-500 Semi-arid 37501-700 Sub-humid 8

Source: Food and Agriculture Organization (FAO)13

In the major part of the country there is a single wet season in summer and the bulk of the rain falls between the months of November and March. Annual rainfall distribution is skewed such that there are more below average than above average rainfall years in a given multi-year cycle which creates high seasonal variations across the country (Figure 1). The high seasonal variations are accompanied by high spatial variability. The annual potential evapo-transpiration exceeds annual precipitation by a wide margin throughout the country, hence drought conditions are a common phenomenon.

Figure 1: Average Annual Rainfall (mm)

12 For purposes of this Paper, microhydro power projects shall refer to all small sized hydro power based projects up to 10 MW of capacity, including so called pico-hydro and mini-hydro.13 http://www.fao.org/ag/AGP/AGPC/doc/Counprof/namibia.htm

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The rivers that originate within the country are short-lived, and the storage dams on such rivers are subject to high losses through evaporation. The country shares three perennial rivers (and consequently the specific assignment of water rights) with Angola on the Kunene River, with Botswana on the Okavango River, and with South Africa on the Orange River. A proposal to construct a 20MW hydro dam at Popa Falls has faced the strong opposition of Botswana’s population over social and environmental considerations, while developments of small hydro plants on the Lower Orange River14 is obstructed by unresolved disputes over the location of the boundary on the shared river.

The Kunene River which originates in Angola and forms the Northern border with Namibia, has a multiuse energy conversion potential. According to the Lower Kunene Hydropower Scheme Feasibility Study15 there are 12 potential hydroelectric projects on the lower stretch of the river, forming part of the border between Angola and Namibia. All these projects are on the main flow of the river, and only one of these is within the size cutoff for a REFIT program, which applies to RE projects less than 10MW. These would be multiuse projects also providing irrigation

14 According to ECB’s records a conditional generation license for the development of a small hydro power project was granted to a project Developer in 2007, for a reported 30MW capacity. The project intended developing a plant on Lower Orange River and is currently inactive due to legal constrains over water rights with South Africa.15 http://www.mme.gov.na/pdf/epupa/ch-2-epupa-tech.pdf (Namibia Ministry of Mines and Energy, November 1998)

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benefits. Conversely, the Baynes Hydropower Project would have an installed capacity of about 465MW, an average production of 171MW, and could be developed as a base-load.

From an economic viewpoint, the lower stretch of the Kunene River would be served by a main reservoir located as far upstream as possible. Subsequent downstream projects would then get the advantage of regulated water and thereby be able to produce firm power. These are reserved to be developed by NamPower as a unified scheme and are not suitable for a REFIT Program.

The Orange River, which forms Namibia's southern border with South Africa, is a perennial river originating in Lesotho. It is extensively used for irrigation in South Africa and dammed up several times. NamPower estimates that the lower Orange River holds potential for an additional generation capacity of 80-120MW. Notwithstanding a clear resolution between the two countries over the equitable allocation of rights over the Orange River, according to some reports16, it appears that the Government of Namibia is pursuing plans to develop the Orange River hydro power plant with the financial support of the Government of Germany. The scheme would entail the development of up to nine small hydroelectric power stations, ranging from 6MW to 12MW, along the Lower Orange river, which has the estimated 80-120MW total power generation potential. The report indicates that the first phase of the feasibility study for the project has been completed. The next step is for the conclusion of environmental and technical studies that would enable decisions on the project site and tariffs. However, the project will be developed by NamPower as a unified scheme and would not be a candidate for REFITs.

Okavango River starts its flow in neighboring Angola, running through Namibia and ending in Botswana in the Okavango Delta. A preliminary feasibility study carried in 2009 evaluated the river’s potential for the 20MW Popa Falls Hydro Power Project17. NamPower has indicated that the project is too small to make much difference in the country’s power supply, although this could be revisited at some future date. In addition, the assessment found that the plant would bring an inequitable distribution of costs and benefits between the two countries, with Namibia primarily benefiting and Botswana suffering most of the environmental costs, through reduction of biodiversity and loss of important natural habitats. Nonetheless, such a complex, multi-use hydro scheme, even if found to be feasible, most likely would be developed under a cooperative approach involving multiple agencies and communities and therefore would not be a candidate for any immediate REFIT Program.

Recommendation for Microhydro REFITs: The above projects are the only known locations with hydroelectric potential in Namibia. Since all of the inland rivers are short-lived, it is highly unlikely that there are any other feasible sites for hydro power projects. There is no evidence of any significant and feasible potential for small scale, independently-owned grid-connected hydroelectric power in Namibia that could be developed in response to a REFIT. Accordingly, it can be concluded that the few potential hydro projects that have been identified in Namibia are not viable and cannot successfully motivate microhydro development under a REFIT Program.

16 http://www.gasandoil.com/oilaround/europe/59935985ea207740df9781489f6cdbcf 17 Technical Report on Hydro-electric Power Development in the Namibian Section of the Okavango River Basin; http://iwlearn.net/iw-projects/842/reports/namibia-reports/technical-report-on-hydro-electric-power-development-in-the-namibian-section-of-the-okavango-river-basin.pdf

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Assessment of Feasibility for Solar PV REFITsNamibia is endowed with abundant solar irradiation, reportedly ranked among the highest in the world. Mean irradiance by the Global Horizontal Irradiance (GHI) metric, which measures radiation captured by stationary receptors (fixed panel solar photovoltaic), is estimated at about 5.8 to 6.2 kWh/m2/day and there are approximately 330 days of full sunshine per annum throughout the country. This level of annual mean irradiance is quite uniformly distributed throughout the country (Figure 2)18. The seasonal variation in the level of GHI is such that

18 The resource maps presented in this figure and the following three are the result of modeling conducted for Nexant by 3Tier Environmental Forecasting, www.3tier.com. The solar resource data are drawn from satellite-based observations and have an estimated uncertainty of 5% (for GHI data) and 9% (for DNI data). The wind resource data are based on 3Tier’s proprietary Numerical Weather Prediction (NWP) model, which integrates topographical data, available land-based observations from weather facilities worldwide and atmospheric physics modeling. The Namibia model run had a resolution of 500 meters and an estimated uncertainty is on the order of 8-9%. Nexant intends to conduct a second run of the solar and wind mapping exercises, provided recent

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approximately 75% of the country’s surface area (all but the northern region bordering Angola) records irradiance in excess of 7.5 kWh/m2/day during the summer months (November to January), while the corresponding winter minimum is 3.6 kWh/m2/day and limited to the southern third of the country. This seasonal pattern is illustrated in Annex 2.

Figure 2: Annual Mean Irradiance, GHI (w/m2)

In contrast, the radiation available for capture by solar tracking technologies (including CSP and tracking PV) presents greater regional variation. Irradiance levels as measured by the Direct Normal Irradiance (DNI) metric show pronounced maxima on the order of 7.8 kWh/m2/day in the central-north region (including Windhoek) as well as in the southwest and inland south (south of Keetmanshoop and Karasburg – Figure 3).

The seasonality of the solar resource measured by DNI exhibits far more regional variability, with maximum levels on the order of 9 kWh/m2/day moving between the southwestern quarter of the country in the summer months to the northeastern quarter of the country in the winter months, as shown in Annex 3. Because central-north Namibia shows irradiance at levels close to the summer and winter maxima observed in the southwest and northeast, respectively, it winds up exhibiting higher annual mean irradiance levels. The more localized areas in the southwest

measurements collected by different renewable energy stakeholders now active in the country are made available.11

with irradiance near the maximum annual mean are likely explained by the lack of any cloud cover at any point during the year.

Figure 3: Annual Mean Irradiance, DNI (w/m2)

The generation potential of solar PV in Namibia is not limited by the resource or the space but rather by the amount of PV power that the Namibian grid can accommodate in terms of network stability and how it fits into the overall generation mix. From a technical standpoint, interconnecting a solar power plant to the distribution system should normally be feasible in locations where safety considerations, equipment protection, reliability, and power quality aspects can be addressed by NamPower. NamPower will need to put restrictions on connections for areas, primarily on the long radial 33 kV lines, where the distribution network is weak. This will help guide developers to find the best locations where the grid can support solar power plants and irradiation level is the best.

Namibia has excellent potential for CSP and PV technologies. According to the ECB, there are several applications under review for a conditional generation license, including projects for a proposed capacity size of 4MW and 10MW.

Recommendation for Solar REFITs: A REFIT for grid-connected solar PV is feasible, because there are conceivably a large number of potential locations where facilities of up to 10MW might be installed, particularly in the central and northern regions of the country where the transmission and distribution networks are well developed and where the solar resource is even slightly more attractive than the rest of the country. The limitations of distribution-voltage

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systems in rural areas may limit the aggregate amount of capacity installed at facilities connected at 33 kV or 66 kV, but larger blocks of capacity could be contemplated in locations close to the high-voltage network. In contrast, it is not clear that a REFIT for CSP projects makes sense, given the economics of CSP technologies, which require large-scale installations to bring costs down close to those achievable with PV technologies.

Assessment of Feasibility for Wind REFITsNamibia’s wind resource is located along the country’s Atlantic coastline, primarily in the southwest, together with the northwest coast and areas at higher elevations in the mountains and highlands up to 500 km inland. The most attractive areas feature Class V resources, with power densities from 500 to 600 w/m2 (at 80 meters) and wind speeds in the range of 8-9 meters/second (m/s). These are concentrated in the southwest between Lüderitz and Oranjemund, and in smaller areas further north. The coast immediately south of Walvis Bay, Namibia’s largest port, is the site of Class III and Class IV resources, with power densities on the order of 400 w/m2 at 80 meters, with wind speeds on the order of 7 m/s (Figure 4).

Figure 4: Power Density, at 80 meters (w/m2)

During the course of the year, the winds along the coastal region shift between the southwest and northwestern regions of the country, such that the wind resource in the southwest is strongest from spring though autumn (September to March), while the northern regions experience

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stronger winds during the winter months. Since rainfall in Namibia comes in the summer months (primarily in the interior highlands of the Northeast draining into the Kunene and Okavango rivers, as shown in Figure 5), the wind resource in the southwest, as opposed to the northwest, provides the basis for seasonal complementarity between hydropower and wind power. The regional and seasonal variability of Namibia’s wind resource is illustrated in Annexes 4 and 5.

Figure 5: Wind Speed, at 80 meters (m/s)

Prospective IPPs have focused on these sites in Luderitz and Walvis Bay due to existing civil and grid infrastructure. The capacity factors for Lüderitz and Walvis Bay, measured at 50m hub-height, are estimated as 35% and 21%, respectively. The annual average wind speeds are estimated at 7.5 m/s in the Lüderitz Golf Course and at 6.8m/s at Walvis Bay. At these statistics, the sites suggest strong potential for the development of economically Viable Projects. According to a study19 on electricity supply and demand in Namibia, it appears that the country’s wind generation has the potential to surpass the electricity demand, provided it is fully exploited and is limited only in terms of the practical and technical grid integration limits for intermittent, unpredictable resources. Further on, the study assumes that the maximum installed capacity from grid connected wind farms might be limited to 90MW, although in most planning scenarios it

19 REEECAP Electricity Supply and Demand Management Options for Namibia. A Technical and Economic Evaluation http://www.reeei.org.na/admin/data/uploads/Namibia%20Electricity%20Supply%20Demand%20Options.pdf (2008)

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does not exceed 60MW. Limiting wind to less than 20% of the overall capacity mix is necessary because Namibia’s facilities currently lack enough storage capacity through which the intermittency of wind resources can be mitigated and grid reliability ensured. Additionally, since forecasts of wind generation over a 24 hour period have a large uncertainty, too much wind power in the overall resource mix would create a problem for Namibia’s power system operations and scheduling purchases from Eskom as NamPower has to provide an hourly schedule of the required imports 24 hours in advance.

The wind power sites at Lüderitz and Walvis Bay are located in proximity to the Regional Electricity Distribution (REDs) and NamPower transmission and distribution grids. Considering the capacity of the current grid infrastructure to deliver the wind power that would be generated at Lüderitz, the maximum size of a wind park is currently estimated at 30MW. Since the wind resources are substantially better in Lüderitz than in Walvis Bay, it can be assumed that any wind park development would commence in Lüderitz up to the capacity of the grid. However, beyond the 30MW capacity, further wind parks would be developed in tandem with transmission enhancements. Detailed system studies will need to identify what measures, such as addition of gas turbines, the power system would require to be able to absorb larger amounts of intermittent resources. From NamPower’s standpoint it may be more advantageous for capacity to be distributed between multiple sites (such as, including Walvis Bay, Luderitz, Oranjemund) to enhance the firm capacity value of the facilities when taken together.

Current plans call for ECB to develop a Formal Tender Process specifically targeted to the large utility-scale wind farms at Lüderitz and Walvis Bay that are identified in the generation expansion plan. Since any surplus capacity on the radial lines serving the Lüderitz and Walvis Bay sites may be utilized for these procurements (and considering that the combined potential for utility scale wind projects at Lüderitz, Walvis Bay and Oranjemund exceeds the maximum overall target for wind power established for the country as a whole), it seems that the scope for additional procurement of wind power beyond these projects is very limited.

Recommendation for Wind REFITs: If most or all of the national target for wind power development will be procured from utility scale plants using a formal tender process, and if these projects utilize the remaining surplus capacity of the grid serving the coastal area where the wind resource is the most attractive, it seems the scope for additional development, beyond the projects already in the planning stages, may be minimal at this time. This is particularly so, if the most likely scenario for wind integration in Namibia is to start with these coastal projects 20 as a Model and move onto other wind sites later on, by which time the cost parameters would have changed and new REFITs would have to be established.

20 Three wind power projects have been proposed at Walvis Bay and Lüderitz, with a combined capacity (based on the original licenses issued by ECB issued in 2008 and 2009) of 154 MW. Since that time, all three Developers have conducted measurement campaigns, with disappointing results at one of the sites. As a result, only two Developers, Diaz (formerly Aeolus) and Innowind, appear to be actively pursuing their projects, at Lüderitz and Walvis Bay, respectively. The two facilities could deliver 104 MW of new generation capacity if built in accordance with their ECB licenses. However, there is still some uncertainty as to whether the projects will go forward and if so whether they will be implemented with a total capacity in line with their original license amounts.

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It should be noted that Nexant’s scope of work includes an activity to organize and direct, on behalf of ECB, a Wind and Solar Mapping of Namibia. As further information becomes available on the wind potential in various parts of the country, the status of existing IPPs, and the preferred approaches to procurement, it may become clearer whether or not it would be productive to institute a wind REFIT. In the event that neither of the potential projects (that are larger than 10MW) advances, then a REFIT for wind energy might be instituted to fill in the gap. Until such time, however, the need for a wind REFIT remains inconclusive. The government can defer the decision on whether to proceed with a wind REFIT until after the utility-scale wind projects are developed.

Assessment of Feasibility for Biomass REFITsA country’s potential for biomass fuels is generated by energy crops21, forestry residues, agricultural and/or municipal/industrial waste. Since only 2% of Namibia's land receives sufficient rainfall to grow satisfactory quantities of crops for the production of fuels, there is almost no potential in Namibia for production of biomass fuels from energy crops. Similarly, the country’s industrial wood and wood product needs are met from imports22. Consequently, the available biomass is simply not of the size or quality required for electricity production using forestry residues in Namibia. At the same time, there are no agricultural waste projects given the limited water resources availability for agricultural purposes, as discussed above.

Nonetheless, it appears that there is a considerable biomass resource from a species of tree generically referred to as “invader bush”. The Desert Research Foundation of Namibia (DRFN) has attempted the implementation of a concept referred to as CBEND (Combating Bush Encroachment for Namibia’s Development), which aims to demonstrate the gasification technology and identify the operational and grid integration issues for a development program that ultimately would target up to 60MW of wood gasification. Considering the size of the encroached land area, the resource to be sustainably harvested could support more generation capacity. NamPower has recently commissioned a study of the invader bush resource and potential technologies for utilizing it for gasification, standard combustion, torrefaction, co-firing, etc. The study is scheduled to be completed by September 2012 and will include a pre-feasibility study of a 10-30MW grid connected power generation facility. It is apparent that NamPower’s objective in assessing alternative uses for the invader bush resource is to determine if larger facilities could be commercially viable, and to evaluate the possibility that it would be the owner and operator of these facilities.

Recommendation for Biomass REFITs: The potential for a biomass REFIT is inconclusive at this time. The feasibility of generation based on the invader bush resource is still being studied, and the applicability of existing technologies, which have been demonstrated in other parts of the world, has not been established conclusively in this context yet. One option is to defer the decision on issuing a biomass REFIT until the feasibility of the invader bush concept is better understood and the need for a REFIT can be revisited. Alternatively, Namibia can use a case-by-case approach to developing PPAs with biomass developers, if need arises.

21 Viable energy crops include corn, woods (i.e. willow, popular, eucalyptus) and perennial grasses such as miscanthus, sweet sorghum, and phalaris. 22 According to the U.N. FAO, 8.9% of Namibia is forested.

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1.4 THE POLICY PARADIGM OF A REFIT PROGRAM

Overview of Key REFIT PrinciplesA REFIT Program is a regulated, predetermined pricing mechanism for the sale of electricity generated from eligible RE resources as designated under the policies of a pre-announced Program. In general, well-structured REFIT policies support the development of new supply based on RE generation in a synchronized approach by,

(i) Unlocking the RE potential: There is a momentum rationale which prompts a country to determine whether to integrate RE technologies in its generation mix. Most times such ripeness is driven by a chronic surge in the domestic energy demand coupled with energy security concerns and the need to displace more onerous supply alternatives such as imports or diesel, the latter being also environmentally onerous.

(ii) Enabling the IPP environment: The REFIT is incentivizing qualified investors such as IPPs to develop viable power generation projects from RE technology resources.

(iii) Guaranteeing access to the national grid: The commercial rationale of the REFIT is driven by the cost-plus-return methodology that offers IPPs the benefit of a reasonable rate of return on their investment in a regulated environment. It is customary for a country, with a grid system that is inherently less stable, to limit the amount of RE technologies that can be in operation. Effective utilization of RE technologies is achieved by integrating an adequate installed capacity from grid connected RE resources at an acceptable rate of return on the IPPs’ investment.

There are a number of prevailing requirements for the development of a successful REFIT Program. Some of the key requirements are listed below:

1. The Offtaker. The REFIT Program must designate23 an entity to take the energy generated by an IPP from an RE resource. The Offtaker must be creditworthy and have the financial liquidity to fulfill its offtake obligations for the amounts of electricity agreed, at the REFIT price specified, for the duration of the PPA signed between such Offtaker and the IPP.

2. The PPA. The sale of electricity is contracted in a fixed-term, legally enforceable agreement. The project to generate the electricity to be sold under the PPA must be

23 NamPower seems to be the natural entity to be designated as the Single Buyer for the REFIT Program. Having multiple entities designated would subtract from the “if you build it, we will buy it” message, as there would be no obligation on any one to Offtake the power generated from a Viable Project, thus defeating the purpose of a REFIT.

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viable in technical, commercial, financial, economic, environmental, regulatory, legal, and other relevant aspects and state the REFIT price. It is customary practice for REFIT Programs to allow the project developer to negotiate a PPA for a term that extends beyond the loan maturity and matches the operating life of the project, usually about 20 to 25 years. The Offtaker will have a take-or-pay obligation with no recourse to demand variations and no discharges from the obligation to purchase all energy delivered, except for pre-specified circumstances involving direct or indirect consequence of the IPP’s negligence or breach, and agreed upon events of Force Majeure. The contract would specify the agreed allocation of risks between the parties and the assignment of rights and obligations.

3. Transmission Connection Agreement (TCA). The purpose of a TCA is to define clear and transparent terms regarding the assignment of rights and obligations between the Transmission Network Provider and the IPP. As such, it is a critical and complementary accompanying document to the PPA, often negotiated by the same parties when the Offtaker happens to also be the Transmission Network Provider that owns and operates the Transmission Network. Generally and unless agreed otherwise, the connection costs for RE stand-alone projects larger than 1MW24 are covered by the project developer. However, REFITs are pre-specified, therefore, including an average connection cost (which is a function of a representative distance to the grid for all the potential project sites) will punish sites above such average distance with a lower REFIT and reward sites closer than such average distance with a higher REFIT. Similarly, the cost of an extension of a network being shared by more than one IPP is customarily born by all the beneficiaries. All such connection costs should pass through to the end users. The transmission line has to be built or reinforced according to the Offtaker’s specifications (which may also be the owner and operator of the network and thus responsible for its maintenance.) The rules for grid connection and associated connection costs should be clear, so the developer knows the costs to bear.

4. REFIT Tariff. The REFIT Program must be endorsed by the promulgation of a regulatory framework (either following legislation or not, as local circumstances may require it) with clearly defined terms for eligible projects, the timeframe for which the Program is available, the prices offered, which should vary by resource type and project size, rules for annual adjustments on such prices (for inflation and for foreign exchange fluctuations), and possible generation ceilings for each such resource type so as to control the resource mix for intermittence and cost mix reasons. Other rules for the transparent, orderly, and predictable implementation of the Program (such as creation of a one-stop-shop, definition of what constitutes a Viable Project, etc.) should also be considered depending on local institutional framework.

5. Cost Recovery Alternative. In the event that a category of RE generation is more expensive than another generation source (i.e. the generation source that is displaced

24 In general according to Standard Utility Practice, projects below 1 MW are typically located behind the meter at the customer premises. Such projects are termed “distributed generation” and are subject to special rules that are normally covered under special regulations and handbooks issued by the distribution company.

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by the new RE generation), there must be either a source of government subsidy or a regulatory decision and procedure for raising end-user tariffs to cover the additional cost associated with RE generation. Some categories may not need any subsidy or end-user tariff increases. The critical element here is that such decisions must be made at the distribution tariff level rather than compromise the cost plus “acceptable return” coverage principle for remunerating IPPs, which is a sine-qua-non to mobilize the private sector.

6. Grid System. Usually the best sites for new RE generation projects are widely distributed geographically. Grid-connected RE projects will not be viable in areas where it is prohibitively expensive to build a connection to the grid. Although off-grid or micro-grid RE is an alternative, managing intermittency often becomes a problem. Most countries need to invest in new transmission lines to develop generation from RE technologies effectively.

7. Intermittent Generation Integration in the Power System. Some categories of RE generation, such as wind power, are intermittent. They do not provide generating capacity dispatchable for base load. As such, the amount of capacity sought by certain resource bases in the REFIT Program must not exceed the operational limits of the power system, i.e. the amount of generating capacity plus imports available to meet demand when the wind is not blowing. Furthermore, as REFITs can be applied at distribution level and some of the distribution grids are not strong enough to manage intermittent renewables, small and gradual introduction with balanced resources would be required25. The REFIT Program may, therefore, need to specify the maximum amount of RE generation by resource type that can be contracted under the REFIT Program.

8. Quantitative Targets: It is customary practice to offer the REFIT prices only until the pre-determined ceiling of capacity per resource base is reached, such as a target level of onshore wind power capacity in MW. This is necessary to conform to system reliability requirements as well as to control the cost of the resource mix. It is perfectly acceptable and does not signify a lack of long-term commitment, as the ceilings can be increased, but after re-evaluating the new cost and resource mix levels, once the ceilings are reached. Developers with contracts already signed under the Program, will nonetheless, have assurances that their signed long-term PPA will

25 The Program does not impose a restriction on connecting projects at either distribution or transmission level. This is a matter of project viability (based on load profile, grid connection point, etc.). Nonetheless, due to its proposed range of 10kw-10MW, the connection would be suitable to be made at distribution level (a 33kV distribution line should be able to carry up to 15MW of power comfortably.) On a case by case basis, depending on size and connection point, projects will raise technical challenges in balancing the grid, but instead of blanket restrictions, these are better addressed by case specific methods available to address such constraints, such as (a) connecting larger projects to a transmission level voltage, (b) scaling the project to a lower MW size, or (c) asking the project Developer to add protective gears for grid stability, among others. A weak distribution system, unless upgraded as required, will significantly limit the addition of new generation capacity from RE projects in that area. Case in point, the data collected on the CBEND biomass pilot project indicated that the project was not operational due to technical constraints with CENORED’s 33kV distribution network which could not take 250kW of power.

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be implemented for the entirety of its duration, as the limitations will be on subsequent additions of capacity26 .

Pricing Premise for REFITsIn reference to RE based generation, NamPower has set up the ceiling at 20%27 of installed capacity, aiming to engage IPPs to develop RE generation capacity28. To achieve this, Namibia must commit to a policy and regulatory framework that enables private participation in the generation market via IPPs, for an adequate, cost effective, and efficient utilization of RE resources and their integration into the electrical grid.

To this end, the REFIT Pricing Model for Namibia takes as a self-evident truth that the private sector, irrespective of all other social considerations, will be mobilized if and only if its costs are covered and it is provided with an “acceptable return” to its investment (i.e. its equity portion.) In doing so, it is important to cap that “acceptable return” so that the price is not excessive but adequate enough to mobilize the private sector. It is also important that the resources used in a proposed project generate an “adequate return” on capital used (i.e. debt plus equity) to signal an efficient use of the resources allocated to the project. In this Paper, we seek those prices that can meet both of these criteria at a return that can be set by policy makers without having to resort to government funds, subsidies, international grants, or other concessionary credits.

Therefore the proposed REFIT for each resource base and size category is presented not as a single figure but as a choice from a matrix of possible prices depending on how the policy makers choose to fix the CAPEX, OPEX, Capacity Factor, and targeted “acceptable return” variables from among a Base Case, High Case, and Low Case scenario. Furthermore, the REFIT Pricing Model gives the policy makers the flexibility to target the “acceptable return” from two different perspectives (i.e. equity alone and debt plus equity) , as follows:

The Post-tax Return on Equity (ROE) analysis which looks at the RE project from the investor’s point of view, such as an IPP, who asks the question What REFIT do I need to get to achieve a desired return on the equity invested? and

The Pre-tax Internal Rate of Return (IRR) analysis which looks at the project from a resource allocation perspective and asks the question What REFIT do I need to get to ensure that all resources used in the project obtain a desired return on the total debt plus equity employed, irrespective of how the project is financed and irrespective of the country’s tax regime?

26 Not all RE projects will come on line at the same time. The best practice for the grid operators in the US is to accept applications for RE projects on a “cue” system: project Developers are evaluated on a first-come first served basis (if proven Viable.) Setting ceilings for the development of RE projects under the REFIT Program and analyzing each project for its Viability allows for a tiered approach taking into account Resource Availability, Grid Reliability, and Project Economics.27 According to “Wind Talks Namibia” a NamPower presentation of November 2011.28 Wind Talks in Namibia, Grid Situation in Namibia, a power point presentation by P.I. Shilamba of NamPower in November 2011, Windhoek.

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The first is an investor’s question trying to decide if the price given for a specific project is adequate enough to invest in it over alternative investment opportunities available to the private investor. The second is a policy maker’s question trying to assess whether the price given reflects an appropriate allocation of resources used (total debt plus equity) to make the project possible.

Regulations to Facilitate Implementation of the REFIT ProgramThe successful implementation of the REFIT Program is contingent upon the adoption of accompanying regulations that will help mobilize the private sector participation in the generation of power from RE technologies. As said earlier, a key element for the success of a REFIT Program is to maximize predictability so that would-be developers would know how the different considerations in the enabling environment affecting the project structure will be treated and how risk allocation arrangements of the project, over and beyond offtake price, will be apportioned between the parties. Without such clarifications articulated in the form of Regulations, REFIT prices alone are inconclusive to make a determination of whether a project will be adequately compensated to cover its costs and provide an “acceptable return.” The objective is to reach a level of clarification from the outset so that the REFIT Program’s message to the private developers is “if you build it, we will buy it” as long as they put together a Viable Project. Otherwise, a REFIT price gets eroded, first, by the various points left undecided and thus to be negotiated (connection costs, inflation treatment, etc.) and, second, by the unpredictability of the environment in which the project is to operate (duration for the Program, carbon credit treatment, etc.). This reduces the ability of IPPs and their bankers to project cash flows and assess associated risks, thus making it impossible to establish the viability of the project. Alternatively, clarification on such elements allows would-be developers to confidently spend the required money upfront to structure their projects and put together a bankable feasibility study, with the confidence that if they do a credible job then the public utility will have an obligation, under proposed Regulations, to buy the power at a defined price and with predictable risk allocation arrangements.

In what follows, twelve key aspects of the enabling environment and/or risk allocation arrangements relevant to all projects are singled out and an associated Regulation is articulated which aims to define an equitable treatment for the developer and Offtaker.

To be credible, a REFIT Program has to be fair to IPPs and their investors as well as to the Offtaker NamPower. The Program must not unduly expose NamPower to obligations they should not undertake while, at the same time, it should give assurances that a Viable Project that meets certain eligibility requirements will find its place in the system. Thus there should be Regulations that limit certain Viable Projects by distance, Program ceiling, etc. and also grant NamPower the opportunity to make its own assessment of project viability, including over aspects that may be subjective in nature (such as assumptions about the future, qualification of contractors, operators, etc.) At the same time, however, there should be a presumption, as upheld by the Regulator, that if a project is proven viable and meets the accompanying Regulations, NamPower should sign a PPA with the qualifying IPP. Thus,

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REFIT Regulation 1. The Offtaker NamPower29 and the IPP qualified under the REFIT Program shall make a good faith effort, upon proper licensing by the ECB, to enter into a take-or-pay PPA, in compliance with the REFIT conditions and associated PPA Guidelines, provided the Project meets the criteria specified in the Regulations under the Program.

To ensure only Viable Projects are accommodated (even though project viability is based on assumptions regarding the future which can be subjective), the Program must make provisions that a developer has to establish the proposed project meets the standards of best practice in its conception, design, planning, and execution in each of the disciplines involved such that it is feasible with respect to technical, commercial, financial, economic, environmental, legal, and other relevant criteria. Thus,

REFIT Regulation 2. Projects must be technically, environmentally, and legally viable and must meet the financing criteria of their creditors and investors. NamPower has the right to withhold signing a PPA unless the project is a Viable Project which shall mean a project involving the construction of a power generation plant which in its conception, design, planning, and execution meets the standards of best practice in each of the disciplines involved that will render such project feasible with respect to technical, commercial, financial, economic, environmental, regulatory, legal, and other relevant criteria.

To be flexible, the REFIT Program must not keep prospective eligible projects captive to its regime but subjects itself to the discipline of the marketplace where willing buyers and willing sellers may opt to by-pass the Program and reach their own independent arrangements outside the Program. Thus,

REFIT Regulation 3. All projects shall have the right to enter into willing buyer – willing seller arrangements with offtakers other than NamPower, at mutually agreed price levels, irrespective of the REFIT levels, subject to proper licensing. In line with the take-or-pay provisions, there shall be only one offtaker in each PPA.

To avoid generalizing connection costs, REFITs must be calculated on a cost plus return basis before incorporating any connection costs, as these will vary depending on distance to the grid. Generalizing connection costs would lead to REFIT prices which are more attractive for projects closer to the grid and less so for projects further out, all else being equal. There still remains the need to account for connection costs without leaving NamPower exposed to a limitless liability to connect any project deemed viable, irrespective of distance to the grid. Thus,

REFIT Regulation 4. Only projects that are within [specified distance, say 10] km from the grid sub-station at the time the PPA is signed shall be eligible for REFITs and without any penalty or reward for the distance from such grid. Nonetheless, NamPower shall, at its sole discretion, retain the right to accept or reject projects beyond [specified distance] km30 (i) for off-grid development, or (ii) for a negotiated discount on the REFIT price,

29 There has to be only one designated Offtaker with the obligation to buy if the project is proven Viable. 30 In circumstances beyond 10 km, NamPower may still be the party best positioned to absorb the risk associated with getting rights of way for the transmission connection lines and do so at least cost. However, in its discretion to accept or reject such projects, it may or may not assume such risk after it assesses the merits of the project in question and its impact on the country’s electrification efforts.

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based on the extended distance beyond [specified distance] km, or (iii) at the IPP’s offer to bear the costs and build the line beyond the [specified distance].

To protect NamPower against connection costs, it has to be assured that it will recover those and also that it will not be exposed to unlimited liabilities to connect eligible projects that meet Program Regulations and criteria. Accordingly, during initial project review (see Section 8 for Application and Project Screening Protocol) and before licensing a project, ECB, following consultations with all affected parties including NamPower, should be in a position to assess if a project, given its size and distance to the connection point at the grid, is suitable to undertake and burden consumers with its associated connection costs. Thus,

REFIT Regulation 5. NamPower shall be allowed to pass through any transmission connection costs associated with connecting projects, properly licensed by the ECB and eligible under the REFIT Program.

To avoid generalizing land costs, REFITs are calculated on a cost plus return basis before incorporating any land costs and for a 20 year useful project life. Generalizing land costs (rural vs. urban, etc.) would lead to REFIT prices where projects on low cost land receive higher than targeted returns and projects on high cost land receive lower than targeted returns. Thus,

REFIT Regulation 6. All land for the project sites to be built on government owned land shall be passed on free of charge31 to the developer under a Build-Own-Operate-Transfer arrangement (unless the associated PPA is renewed in 20 years), if the appropriate concession rights to build such project and the appropriate licenses are duly obtained32 by the developer. Projects to be built on privately owned sites, with duly obtained licenses and concession rights to build such project, will be subject to an extra remuneration not exceeding 5%33 of the REFIT, verified by independent appraiser valuation and as mutually agreed by NamPower and the developer.

To ensure equal fiscal treatment, REFITs are calculated for targeted returns after including applicable import duties and corporate taxes. If the Government chooses to offer tax holidays in order to reduce prices across the board, such a measure could be applied on an equal basis for all projects and supported by an applicable REFIT Regulation. In turn, this would remove aggregate costs on NamPower and remove possible pressures on consumer tariffs. Thus,

REFIT Regulation 7. All projects under the REFIT Program shall be subject to the same duties for imported goods and same corporate taxes on profits, unless the developer is already a beneficiary of an existing, ratified Implementation Agreement or Concession Agreement already in effect with Conditions Precedent already satisfied at the time of submitting an Expression of Interest as per the provisions of the REFIT Program, which

31 If (a) there are regulatory/legal restrictions against passing government owned land free of charge to a Developer for the development of RE projects, or (b) there is a special regime of allocating land rights in Namibia, or (c) this cannot be accommodated for political or other reasons, then the Regulation would have to be rephrased to add cost of such land lease to the REFIT price to compensate the Developer for the cost.32 The issuance of these licenses and concession rights is the control mechanism for the Government to prevent projects from being built on land reserved for alternative purposes.33 This ceiling seeks to estimate the value of land in such projects, so that together with the provisions of seeking an independent appraisal valuation and the mutual agreement of the PPA parties, it provides a framework for reaching agreement.

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Implementation Agreement or Concession Agreement already specifically grant import tax exemptions or tax holidays already in effect or to go into effect as already agreed.

To enable foreign banks to provide the long-term financing needed, currency mismatches between project revenues and debt service must be avoided. Most renewable energy projects within the 10MW category have cash flow profiles that necessitate debt repayment periods between 5 to 10 years. This necessitates long-term funding that is limited in the domestic market and potential IPPs are likely to seek debt from foreign lenders. These will typically be denominated in foreign currency, possibly ZAR, US$ or Euro. In all these cases, which are likely to be the norm, if the REFIT payments are denominated in local currency there will be a currency mismatch between revenues and debt service obligations. A currency mismatch can be mitigated either by having revenues paid in the currency in which the debt is denominated, or by hedging the risk against inevitable variations in the exchange rate. The latter is an expensive tool which will be reflected in the price that the developer charges to NamPower. Furthermore, it is often not possible, let alone being expensive, to hedge such long segments from the outset. In case of a mismatch between the currencies in revenues versus loans, foreign banks (that would necessarily have to be relied upon for long term loans denominated in hard currency) would not provide the necessary financing required for the larger sized projects. Thus,

REFIT Regulation 8. REFIT shall be payable in US$, (this can be adjusted to another hard currency by the mutual agreement of the parties to the PPA) provided that projects financed in local currency for any portion of the financing required (long term plus equity) shall be payable in local currency for that proportion of the due payment. Notwithstanding this provision, the actual transaction for the associated invoice can be made in local currency at the prevailing exchange rate34 on the date of such invoice, provided that the parties reach mutually satisfactory arrangements to mitigate convertibility and transferability risks associated with such payments in servicing debt and repatriating capital and profits.

To provide predictability to developers on their future revenues as well as for their standing vis a vis their competitors’ future tariff adjustments, the rules for (a) adjusting REFITs in line with inflation for projects with PPAs under the REFIT Program, and (b) for the REFITs posted from year to year, need to be clear with everyone treated on an equal footing. This predictability is paramount to the success of a REFIT Program, or to mobilizing private sector for any project for that matter. Guarding project value against inflation, which is not in the control of a Developer, is necessary and applicable not only to OPEX but to CAPEX for replacements, Working Capital, variable interest costs payable on Loans (or to compensate the higher fixed interest rate opted, if the project raised capital at fixed interest rates,) and the original Equity Investment base of the project (which are losing opportunity cost, as they could have been invested elsewhere collecting inflation covering market rates.) Accordingly, the proposed REFITs are calculated assuming inflation adjustments. Thus,

REFIT Regulation 9. Indexation shall be applied to old (those post-project completion) and new projects (those pre-PPA signing) in a manner that (i) REFITs stated in Power Purchase Agreements for old projects will be adjusted on the basis of the US$ Producer Price Index (PPI) starting from the year of the PPA at financial closure, and (ii) REFIT

34 Means the US$/NAD offered exchange rate prevailing at the close of business by the Bank of Namibia on the date of the invoice.

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tables (applicable to new project), on the basis of US$ PPI plus differential inflation (as compared to the PPI) consisting of a basket of fuel, cement, steel and labor (unless other cost factors are added in the interim before fixing the methodology). This shall be made public every year by the ECB, so that all IPPs can be assured of a level of price predictability.

To conform to system reliability requirements as well as to control the cost of the resource mix, ceilings for levels of procurement from each of the individual resource bases in the REFIT Program will be imposed by the Government. The initial ceilings may be arbitrarily kept low for select resources bases that are subject to intermittence problems (seasonal wind) and/or expensive (solar) to include in the aggregate cost. In time, depending on the differential rate of additions into the system of each individual resource base, these ceilings could be increased. Once the ceiling is reached, NamPower would no longer be obligated to sign a PPA at the REFIT price for that particular technology, irrespective of the viability of the project. Thus,

REFIT Regulation 10. The […], in consultation with […] and […], shall impose overall ceilings on a per resource basis that may be increased35. from time to time, at the […] sole discretion, to balance out technical intermittence problems as well as tariff impact, depending on the rate of integration of new projects into the system. The initial ceilings, until further notice by the […], shall be:

Solar…………………………………………………………………[XXMW] Wind……………..…………………………………………………..[YYMW]Bagasse……………………………………………………………….[ZZMW]

To credit the Carbon Credits to the Government, which is deemed to be the rightful owner of such credits, REFIT levels are calculated before any Carbon Credit. Splitting the proceeds would incentivize the IPP to collect while also not providing them with too much of a windfall over and beyond the cost plus return intended under the REFIT Program36. Thus,

REFIT Regulation 11. All Carbon Credits shall be deemed as belonging to the Government. However, the Government, at its sole discretion, may choose to split the proceeds at some pre-negotiated proportion, if it deems such partitioning would incentivize a particularly well positioned IPP with experience in this Carbon Credit market to collect such credits.

To give a meaningful duration for published REFITs (adjusted by indexation), so developers can assess the investment environment with some predictability, they must remain for at least 3 years. By the same token, beyond 3 years, core structural assumptions (despite indexing) may shift and should be subject to review. The Regulator should reserve the right to review these

35 As predictability is paramount to the success of a REFIT Program, only increases (not decreases) should be allowed, so private Developers of a Viable Project do not take the risk of having a previously announced ceiling lowered after they have spent money to structure their project. 36 In general, the carbon market allows governments to package credits from REFITs for ‘wholesale’ but this is presently a relatively small share of the market and has its special cumbersome procedures. This option can be evaluated in parallel to implementing the REFIT Program. The key point is that these credits belong to the Government because of the way the REFITs have been priced and the collection on the credits can be implemented in various ways, as long as the regulatory measures assign the government as the rightful owner of the credits.

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REFITs in the second year anniversary of the declaration of the proposed Regulations, provided that only upward revisions and adjustments would be considered and those shall be applicable to Old and New Projects alike. Thus,

REFIT Regulation 12. The Duration of REFITs shall be for 3 years37.

ECB will provide further guidance as to whether the above proposed Regulations would necessitate a parliamentary approval to be passed into law or whether a regulatory act from ECB and/or the Ministry of Mines and Energy would suffice. The proposed REFITs can be viewed as a wholesale version of PPAs, which do not usually require parliamentary ratification. Passing a REFIT Law might strengthen the message of welcoming IPPs into the market, however the process might be lengthy with adjustments more cumbersome to make. Therefore, passing these regulations and their subsequent adjustments under ministerial authority to formulate policy would give maximum agility to successfully implement the REFIT Program.

37 Once a PPA is signed under the provisions of the REFIT Program, the contract will remain for the next 20 years, with prices adjusted only according to the indexation provisions of that PPA agreed upon at the time of signature in compliance with the indexation rules of the initial ongoing REFIT regime. The ongoing published regime of REFITs will be escalated by PPI adjustments (plus differential inflation for steel etc., as explained in the indexation provisions) but that will not affect signed PPAs. In 3 years there will be another set of published REFITs, but again existing PPAs will follow what was signed (with the indexation agreed in the contract and not in the new regime).

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Section 2 The REFIT Model

2.1 THE METHODOLOGY

The fundamental task of the Model is to calculate an energy rate (the REFIT) to be paid per unit of generation in a given size range that will cover the costs and provide an acceptable return for a generation facility in Namibia based on a given RE resource. These costs include capital expenses (CAPEX) to build a facility and ongoing operating expenses (OPEX) to operate and maintain the facility. The Model assumes that Namibia government funds, subsidies, international grants, or other concessionary credits are not used for RE projects undertaken by IPPs, if they are to receive a REFIT tariff.

For each distinct RE base and project size, the Model derives REFITs for multiple CAPEX (3), OPEX (3), and Capacity Factor (3) scenarios, as follows:

CAPEX: Base Cost, Base Cost +10%, Base Cost -10% OPEX: Base Cost, Base Cost +20, Base Cost -20% Capacity Factor (which vary depending on the type of RE base)

Table 4. Capacity FactorsBiomass Solar PV Wind

0.75-0.85-0.95 0.15-0.20-0.25 0.20-0.27-0.34

The Model also fixes a debt: equity ratio at 75:25 for all projects and seeks the REFIT required to produce the Revenue which achieves a selected target Post-tax ROE (Return on Equity) for the investor or, alternatively, a selected target Pre-tax IRR (Internal Rate of Return) for the project’s cash flow, at the user’s preference.

To execute the Model, the user fills in the specifications of the type of plant (RE resource, size) to analyze, together with various parameter variations at, above, or below the Base Case Scenario on Capacity Factor, CAPEX, and OPEX (plus variations on some other key assumptions, such as, for instance, tax rate) and clicks either (a) “Control M” to get (on the Input Sheet) the REFIT that provides a desired Post-tax ROE for the investor to that particular project or a desired Pre-tax IRR for the Project Cash Flow to that particular project, or (b) clicks the "Launch Simulation" button to obtain the REFITs (on two sets of Matrix Output Sheets, one ROE the other IRR driven) for all RE resources at all their sizes (up to 10MW) for the various parameters the user can fix at, below, or above the Base Case Scenario on Capacity Factor, CAPEX, and OPEX,.

The Post-tax ROE analysis looks at the RE project from the point of view of an investor such as an IPP, who asks the question “What REFIT do I need to get to achieve a desired return on the equity invested.” The Pre-tax IRR analysis looks at the project from a resource allocation point of view and asks the question “What REFIT do I need to get to ensure that all the resources used

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in the project obtain a desired return, irrespective of how the project is financed and irrespective of the country’s tax regime.” The first is an investor alternative investment options question, the second is a government resource allocation question.

2.2 PROJECT ROE

The ROE is used to determine the REFIT required to produce a project that returns enough cash to the equity holder to justify their portion of the investment. This calculation considers the final cash flow to the project left for distribution as dividends to equity investors, after payment to other parties including debt service to the lenders and taxes to the government.

The Model projects net cash flows to equity holders after considering the effects of financing and taxes. These cash flows are then discounted over the life span of the project. In this model the discount rate is either input by the user or derived off an input Pre-tax IRR value for the project (please see below) that the user selected. The Model then adjusts the revenue stream by finding the REFIT necessary to cause a cash flow with zero NPV at the given discount rate.

In the ROE driven analysis, the model assumes Post-tax ROE values of 16%, 20%, and 24% 38. and derives corresponding REFITs for (a) each size and resource base scenario and sensitivity case (Capacity Factor, CAPEX, OPEX), and for (b) each specified ROE discount rate assumption. Using a goal seek procedure the Model determines:

the resulting REFIT ($/kWh) that will satisfy the annual revenue requirement to give a zero NPV after tax cash flow to equity investors at the chosen ROE, after paying principal and interest on debt (debt service.)

The corresponding IRR discount rate for the project pre-tax and before repaying debt.ROE driven results are presented in Section 6 of this Report and in the Model’s Excel Sheet “Matrix Output with ROE.”

2.3 PROJECT IRR

The IRR of the project is used to determine the REFIT required to produce a project that is viable at a specified discount rate (i.e. the IRR specified by the user.). This calculation does not view the project from any specific party’s standpoint and thus makes no attempt to determine how the overall cash flows are distributed in accordance with risk or subordination of payment.

IRR of the project is based on the projected capital cost, operating cost and revenue for a given REFIT rate. The model projects (pre-tax operating) cash flows before considering the effects of financing and taxes (commonly known as EBITDA). These cash flows are then discounted over the life span of the project. In this Model, the discount rate (Pre-tax IRR) is either input by the user or derived off a Post-tax ROE input by the user. The Model then adjusts the revenue stream by finding the REFIT necessary to cause a cash flow with 0 NPV at the discount rate (Pre-tax IRR) selected by the user.

38 Note that the Government’s Weighted Average Cost of Capital (WACC) is not relevant here. ECB can decide what ROE level is adequate to attract the private sector and accordingly select the REFIT levels that correspond to that targeted ROE. What will mobilize private investors is not the Government’s WACC but the opportunity cost of the private sector that makes investment decisions based on its available choices.

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In contrast to the project ROE analysis, the project revenue requirements and REFITs (for Pre-tax IRR targeted runs) are essentially independent of the financial assumptions concerning debt size, project depreciation, and taxation. The exception is the impact of these assumptions on short term Working Capital cost and Reserve Accounts, and interest on these accounts.

In the IRR driven analysis, the Model assumes Pre-tax IRR values of 12%, 16%, and 20% and derives corresponding REFITs for each scenario and sensitivity case and for each specified IRR discount rate assumption. Using a goal seeks procedure the Model determines:

The resulting REFIT that will satisfy the annual revenue requirement to give a zero NPV before tax cash flow at the chosen IRR and before debt service.

The corresponding ROE discount rate for equity investors after debt service and taxes.

IRR driven results are presented in Section 4 of this Paper and in the Model’s Excel Sheet “Matrix Output with IRR.”

2.4 BASE CASE REFITS

The following two tables summarize the Model Base Case REFIT results for each RE technology and each size analyzed, one for the ROE driven analysis assuming a 20% Post-tax ROE rate and one for the project IRR driven analysis assuming 16% Pre-tax IRR rate.

Table 5. ROE Driven REFIT Base Case

Technology Size

Post-tax ROE

Project Pre-tax IRR

Rev $/kWy

Capacity Factor

REFIT ($/kWh)

Bio-Mass 0.25 - 0.5MW 20% 21.04% 1,649 85% 0.221Bio-Mass 0.5 - 5MW 20% 19.64% 1,086 85% 0.146Bio-Mass 5 <10MW 20% 18.56% 781 85% 0.105Bio-Mass 5 <10MW (REPEAT) 20% 18.56% 781 85% 0.105Solar < 10kW 20% 22.30% 771 20% 0.440Solar 10 - 250kW 20% 22.31% 738 20% 0.421Solar 250 - 2MW 20% 22.30% 659 20% 0.376Solar 2 - 5MW 20% 20.64% 533 20% 0.304Solar 5 <10MW 20% 19.28% 471 20% 0.269Wind < 10kW 20% 22.30% 587 27% 0.248Wind 10 - 250kW 20% 22.30% 538 27% 0.228Wind 250 - 2MW 20% 22.30% 379 27% 0.160Wind 2 - 5MW 20% 20.64% 326 27% 0.138Wind 5 <10MW 20% 19.27% 297 27% 0.126

For the project IRR analysis and the results shown for the IRR driven REFIT Base Case, the resulting project revenue requirement and REFITs are essentially independent of the financial

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assumptions concerning project depreciation, taxation, and loans for debt financing, except for the (relatively minor) impacts of these assumptions on the cost of Working Capital cost and the income from the Debt Service Reserve Account.

In the table showing results for the IRR driven REFIT Base Case only the Post-tax ROE column is directly influenced by the financial assumptions concerning project depreciation, taxation, and loans for project debt financing. The remaining columns of this table are not.

Table 6. IRR Driven REFIT Base Case

Technology Size

Project Pre-tax IRR

Post-tax ROE

Rev $/kWy

Capacity Factor

REFIT ($/kWh)

Bio-Mass 0.25 - 0.5MW 16% 13.90% 1,367 85% 0.184Bio-Mass 0.5 - 5MW 16% 14.98% 947 85% 0.127Bio-Mass 5 <10MW 16% 16.07% 710 85% 0.095Bio-Mass 5 <10MW (REPEAT) 16% 16.07% 710 85% 0.095Solar < 10kW 16% 13.23% 584 20% 0.333Solar 10 - 250kW 16% 13.22% 559 20% 0.319Solar 250 - 2MW 16% 13.23% 499 20% 0.285Solar 2 - 5MW 16% 14.24% 432 20% 0.247Solar 5 <10MW 16% 15.36% 405 20% 0.231Wind < 10kW 16% 13.23% 448 27% 0.189Wind 10 - 250kW 16% 13.22% 411 27% 0.174Wind 250 - 2MW 16% 13.23% 289 27% 0.122Wind 2 - 5MW 16% 14.24% 266 27% 0.112Wind 5 <10MW 16% 15.37% 256 27% 0.108

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Section 3 Benchmarking REFIT Programs

Only three countries in Southern Africa have implemented REFIT Programs: South Africa, Tanzania, and Mauritius. The others, Angola, Botswana, Madagascar, Malawi, Mozambique, Namibia, Zambia, and Zimbabwe do not presently have such a Program. Botswana, Mozambique, and Namibia may be the next countries in Southern Africa to implement a REFIT Program. Other countries in Africa with REFIT initiatives that have started to gain traction are Ethiopia, Kenya, Rwanda, and Uganda.

The common theme of all these Programs is private sector mobilization. Their varying success is a function of the predictability they communicate to the would-be IPPs over and beyond price levels, in areas such as obligation of Offtaker to sign a PPA when a Viable Project is presented, connection cost treatment, indexation, treatment of currency fluctuation, etc.

The purpose of this Section is to describe the current status of REFIT Programs in select benchmark countries in Africa and draw some lessons from their experience.

3.1 TANZANIA REFIT PROGRAM

Scope of the REFIT Program: In 2008, the Energy and Water Utilities Regulatory Authority (EWURA) of Tanzania adopted a standardized mechanism for Small Power Projects39 (SPPs) to promote rural electrification and alleviate power shortages in the country. The program was designed to establish through the Ministry of Energy and Minerals (MEM) “a framework for development of small power projects utilizing the abundant RE sources” in the country and according to EWURA “[…] accelerate electricity access and promote the development and operation of small power projects among local and foreign private investors.” As such, the key elements of the program are small projects, RE promotion, increased access, rural electrification, and private sector. The Program applies to small hydro, wind, biomass, biogas, solar, waste heat, cogeneration, and geothermal.

Structure of Tariff: The framework for the REFIT is developed according to the Electricity Act of 2008. It involves a series of standardized components whose intent is to reduce negotiation time and cost, and open the possibility of implementing rural electrification projects40.”

Eligible Small Power Projects: These are SPPs that have a capacity ranging from 100kw to 10MW and utilizing an RE resource to generate commercial electricity connected to the National Grid or Isolated Grids in Tanzania.

39 An SPP is defined as a power plant using a RE source or waste heat, or cogeneration of heat and electricity, with an export capacity up to 10 MW.40 Source: http://www.ewura.com/sppselectricity.html.

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A Standardized Small PPA: This is the agreement applicable between the developer and the Offtaker, Tanzania Electric Supply Company Ltd. (TANESCO), for purposes of selling power not exceeding 10MW but not less than 100kW. It is a standard 15-year PPA offered to all SPPs. The Offtaker does not have a legal obligation to sign PPAs for more SPP capacity than it wishes to purchase. As such, a power plant could be built by a large industrial consumer and sell no more than 10MW under the SPP program, even if the capacity of the plant is much more than 10MW.

A Standardized Small Power Purchase Tariff: This is the agreed tariff in the Standardized Small Power Purchase Agreement. There are two types, depending on the type of grid,

(1) For SPPs connected to the Isolated Grids (“mini-grids”): SPPs get a fixed, non-seasonal tariff. It equals the average of (a) Long Run Marginal Cost (LRMC) of generation in the main grid of Tanzania, plus an adjustment for avoided transmission losses, and (b) the average incremental cost of diesel generation on an isolated grid, assuming a new diesel generator. The LRMC is well below the cost per kWh of diesel generation. It is calculated in US cents/kWh and then converted to TZS/kWh.

(2) For SPPs connected to the Main Grid: There is a “base tariff” of which the SPP receives 90% during the wet season and 120% during the dry season. The base tariff equals the average of (a) the Long Run Marginal Cost (LRMC) of generation in the main grid of Tanzania, plus a percentage adjustment for avoided transmission losses, and (b) the projected average cost of thermal generation to be supplied to the main grid in the next forecast year (i.e. the year in which the SPP tariff is effective), plus the same percentage adjustment for avoided transmission losses. Both LRMC and average cost of thermal generation are well below the cost per kWh of diesel generation.

A Standard Tariff Methodology: Given the above, REFITs are based on the avoided cost of energy in the power system and are adjusted annually. Therefore, the developer does not know the prices at which his energy will be sold. However, Appendix A of the Standardized PPA guarantees (a) the developer a Floor Price over the term of the PPA, which is the REFIT in effect at the time of PPA signing, and (b) the Offtaker a Ceiling Price, which is 150 percent of the REFIT in effect at the time of PPA signing, plus an inflation adjustment based on a 5-year moving average in the Tanzania Consumer Price Index. Thus at PPA signing, the developer has a Ceiling Price in real terms.

Particular Implications of the Tanzania REFIT Program 41 : Based on 2008-11 tariff levels shown in Table 7 below (translated to US cents/kWh in Table 8), it can be inferred that SPPs connected to the main grid are mainly small hydro and biomass projects. However, proposed tariffs for 2012 should also support wind projects at the most

41 Sources: All official documents related to the Small Power Purchase tariff methodology, tariff calculations, tariff orders, and Standardized PPAs are available from the web site of the Energy and Water Utilities Regulatory Authority (see http://www.ewura.com/sppselectricity.html).

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favorable wind power sites. At the proposed 2012 tariff, the SPPs connected to isolated grids could have almost any market-proven RE technology, including solar PV.

Table 7. Standardized Small Power Purchase Tariff for Tanzania (2008-2012)

Approved Approved Approved Approved "Prevailing" Proposed 2008 Tariff 2009 Tariff 2010 Tariff 2011 Tariff 2011 Tariff 2012

Tariff TZS/kWh TZS/kWh TZS/kWh TZS/kWh TZS/kWh TZS/kWh

Effective date of approved tariff

01-Jan-09 01-Jan-10 01-May-11 n/a

Date of order approving tariff

10-Jul-09 21-May-10 11-May-11 n/a

Date of public notice for proposed tariff

06-May-09 12-Mar-10 18-Feb-11 20-Feb-12 20-Feb-12

For SPPs connected to the main grid

Fixed tariff (non-seasonal)

100.40 96.11 110.30 121.13 112.43 152.54

Seasonal tariff

(dry season: Aug-Nov)

120.50 115.33 132.36 145.36 134.92 183.05

Seasonal tariff,

(wet season: Jan-Jul + Dec)

90.40 86.50 99.27 109.02 101.19 137.29

For SPPs connected to mini-grids

Fixed tariff (non-seasonal)

n/a 334.83 368.87 380.22 380.22 480.50

* Small Power Purchase Tariffs are published by the Energy and Water Utilities Regulatory Authority at http://www.ewura.com/sppselectricity.html

Table 8. Standardized Small Power Purchase Tariff for Tanzania, 2008-2012

Equivalent Equivalent Equivalent Equivalent Equivalent

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Approved Approved Approved Approved Proposed2008 Tariff 2009 Tariff 2010 Tariff 2011 Tariff 2012 TariffUS c /kWh US c /kWh US c /kWh US c /kWh US c /kWh

Effective date of approved tariff 01-Jan-09 01-Jan-10 01-May-11 n/a

Date of order approving tariff 10-Jul-09 21-May-10 11-May-11 n/a

Date of public notice for proposed tariff

06-May-09 12-Mar-10 18-Feb-11 20-Feb-12

For SPPs connected to the main grid

Fixed tariff (non-seasonal) 7.62 7.29 8.37 9.19 11.57

Seasonal tariff, August - November (dry season)

9.14 8.75 10.04 11.03 13.88

Seasonal tariff, January - July, and December (wet season)

6.86 6.56 7.53 8.27 10.41

For SPPs connected to mini-grids

Fixed tariff (non-seasonal) n/a 25.40 27.98 28.84 36.45

Date used to measure exchange rate

01-Jan-08 01-Jan-09 01-Jan-10 01-May-11 20-Feb-12

Exchange rate, TZS/USD 1135.00 1296.20 1318.40 1490.29 1571.16

*Exchange rates are from www.oanda.com .

Tanzania’s SPP Program is quite different from most REFIT Programs, as the Offtaker simply pays an avoided cost that varies from year to year and does not absorb the price risk associated with the cost of RE based generation. The SPP, on the other hand, faces a significant amount of price risk, because the price in its PPA is adjusted every year by EWURA with no relationship to the SPP’s production costs. The end result is that this creates a risk disincentive for RE generation. Furthermore, because the SPP tariffs are stated in local currency, the equivalent amount in US cents/kWh depends on the exchange rate assumption.

A side result of pricing based on avoided cost and not production cost is that there are no caps on the amount of MW capacity that could be installed under the SPP Program (i.e. pricing does not take into account economies of scale resulting in lower production costs as the plant size increases). The capacity limit is applied to the amount of capacity provided to the grid, not the total installed capacity of the generating facility. In this respect the program encourages investment in power plants larger than 10MW which are used to meet the on-site electricity needs of a large industrial consumer. This is further encouraged by inclusion of power generation from waste heat and cogeneration, broadening the scope of the REFIT Program.

Again a side result of avoided cost based pricing, the grid vs. “mini-grids” price differentiation results in the latter being about three times higher than the base tariff for SPPs connected to the

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main grid. This results in the Program giving a strong incentive for developers to invest in RE generation in areas with mini-grids, thereby encouraging rural electrification42.

One of the implicit objectives of the program is to displace diesel generation with RE generation. If diesel generation in mini-grids will someday be eliminated, then logically EWURA should change the tariff methodology for SPPs connected to mini-grids. Otherwise the “avoided cost” would be seriously overstated.

The SPP Program is relatively new, therefore, it is premature to estimate the total amount of capacity to be built under this program. However, EWURA listed in their 2010 Annual Report three small hydro projects, three biomass and two cogeneration projects. By end 2010, TANESCO had already signed five PPAs with SPPs totaling 24.4MW and was discussing another 27.5MW of potential projects with developers.

Relevance for the Proposed REFIT Program in Namibia:The REFIT Program in Tanzania is not a model for Namibia’s proposed REFITs because it is not based on production costs. The SPP tariff is based on estimates of avoided cost of the system and there is a large spread between the price offered for producers connected to the main grid and the price offered to producers connected to small, isolated networks. Nonetheless the REFIT Program in Tanzania should provide useful guidelines for rural electrification based on generation from small hydro and biomass.

3.2 SOUTH AFRICA RE IPP PROGRAM

Scope of the REFIT Program: At the beginning of 2009, South Africa started to implement policies designed to attract investment in RE IPPs. One of the policy initiatives was a REFIT program approved by the National Energy Regulatory Authority of South Africa (NERSA) on March 26, 2009 in accordance with broad policy objectives defined by the Department of Energy (DoE.) NERSA announced “REFIT to be reviewed every year for the first five-year period of implementation and every three years thereafter and the resulting tariffs will apply only to new projects.” 43

Procurement was to be carried out by a RE Purchasing Agency (REPA) to be initially housed in Eskom’s Single Buyer Office. Later the functions of procurement and trading were separated. The procurement function was assigned to DoE while the Buyer has not yet been identified.

Today that program has been effectively superseded by an RE Independent Power Producer (RE IPP) Procurement program managed by DoE in accordance with Electricity Regulations on New Generation Capacity issued by DoE on May 4, 2011. An RE Fund is being created by National Treasury (NT). The role of Eskom, the vertically integrated national power utility, still remains to be defined. A Ministerial Decision is still needed to define the Buyer under the RE IPP procurement. The Buyer will possibly be an Independent System and Market Operator (ISMO) to be spun off from Eskom in line with a proposed Bill in Parliament as of June 2012.

42 The mini-grid SPP tariff in 2012 may be high enough to support solar PV, although it is not the objective of the Program to support any particular technology. 43 NERSA, RE Feed-In Tariff Guidelines, Decision and Reasons for Decision, March 26, 2009, page 1.

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The REFIT Program proposed by NERSA was a hybrid between REFIT and competitive tendering. While no longer in effect, it has valuable lessons to teach. A number of elements in its application such as (a) high levels of lower limits in project sizes, (b) Rules of Selection Criteria assigning point scores to applicants, (c) transmission connection charges (determined at the System Operator Eskom’s discretion) charged to the developer as a discount on the REFIT, (d) etc. all conspired to subtract from the spirit of what a REFIT Program is supposed to be all about: “if you build it, we will buy it” if it is a Viable Project and with no haggling.

First, South Africa’s REFIT had minimum plant sizes that are high by African standards: Landfill gas ≥ 1MWBiomass ≥ 1MWBiogas ≥ 1MWSmall hydro ≥ 1MW44

Photovoltaic ≥ 1MWCSP ≥ 20MWWind ≥ 20MW45

For solar PV this excludes a very large share of the potential market such as customer-owned PV systems. Arguably investments in small-scale PV could be addressed through a net metering concept and not a REFIT, but this opportunity was not addressed by NERSA. For wind, the minimum size of 20MW is very high by African standards, and it would exclude many small-scale wind facilities in locations where the wind regimes are favorable.

Second, an evaluation matrix table46 required the procuring entity to assign each project a point score, up to a maximum of 100 points, to determine the highest scoring projects to be selected. The primary criterion is the “compliance with the Integrated Resource Plan and the preferred technologies” with reference to the Integrated Resource Plan (IRP)1 targets below:

Table 9. South Africa Renewable Capacity Targets in NERSA REFIT Program of March 2009

44 This size limitation signifies the economies of scale which weigh in more in a country like South Africa where the installed capacity is 44,000MW, compared to Namibia where the installed capacity is 393MW. This underlines the significance of REFITs for Namibia and the pivotal role they can play in electrification.45 NERSA News, official newsletter, July-September 2010, page 8; www.nersa.org.za 46 Schedule 1 of the Rules on Selection Criteria for RE Projects

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Source: www.nersa.org.za

Since Eskom was already developing the first project and undertaking a 100MW CSP, the REFIT Program was de facto limited to 675MW through 2013 – of which 400MW could be wind47. The wind industry response to the IRP1 notice was significantly larger than 400MW. According to a GTZ report, as of July 2009, Eskom had received indications of interest in 5400MW of wind projects. Taking an inventory of these nuances: (a) REFIT Phase 1 had room for only the first 400MW of wind, and (b) selection criteria had to be used to limit candidates down from 5400MW, the selection process was a de facto competitive tender.

Third, and most derailing, were the treatment of connection costs. The System Operator would determine the level of connection cost which would be passed on to be absorbed by the project developer. This requirement is explained in NERSA rules, as follows:

The deep connection cost constitutes the additional infrastructure cost over and above the shallow cost […] for upstream and downstream strengthening of the network, necessary for connection operation of the facility.

The system operator in consultation with network service provider (NSP) will determine the deep and shallow connection cost for each facility, excluding any existing network constraints. The deep and shallow connection costs will be determined for the network infrastructure that would be available at the commercial operation date of the facility.

Any additional cost associated with a specific project sponsor requirements for higher than the standard connection quality of supply of the facility will be considered as deep connection cost and added to the deep connection costs.

Given the provision for recovery of the connection costs in the REFITs, the connection costs for RE facilities shall be financed in full up front by the project sponsor before the commercial operation date of the facility48.

When the above connection costs are added, it becomes evident that project costs were not well defined by the NERSA REFITs, despite the fact that there was an apparent REFIT price.

Structure of Tariff:

47 Construction period for a wind farm might be no more than a year. The Electrawinds project in Port Elizabeth was completed in a record time of 104 days http://www.electrawinds.be/electrawinds_powered_by_nature-electrawinds_artikels.asp?artikelID=14693&taal=en 48 NERSA, Rules on Selection Criteria for RE Projects Under the REFIT Programme, February 19, 2010 (Pages 11-12.)

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In March 2009 (REFIT Phase I), NERSA approved REFIT levels based on the assumptions shown in Table 10. The consensus was “the tariffs offered by NERSA under REFIT are too low to make any RE project viable” and thus, on October 2009 (REFIT Phase II), NERSA approved REFIT levels as shown in Table 11.

Table 10. South Africa REFIT, Phase I

Source: www.nersa.org.za

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Table 11. South Africa REFIT, Phase II

Source: www.nersa.org.za

The above contrasts with Eskom tariffs for the 3-year period beginning April 1, 2010 as set by the Multi Year Price Determination 2 (MYPD2). On September 30, 2009 Eskom requested increases of 45% per annum for the three years and revised same on November 30 to 35% per annum. On February 24, 2010 NERSA approved an annual increase of about 26%, as follows:

Table 12. Eskom Revenues and Retail Rates2010/2011 2011/2012 2012/2013

Allowed revenues from tariff based 85,180 109,948 141,41139

sales (RAND /M)Forecast sales to tariff customers (GWh)

204,551 210,219 214,737

Standard average price (c/kWh) 41.57 52.30 65.85Percentage Price Increase (%) 24.8 25.8 25.9Total expected revenue from all customers (RAND/M)

90,927 116152 148,378

Source: www. eskom .co.za/

It is worth noting from the above comparisons that since the purchase of energy from RE IPPs would lead to cost increases, Eskom, which holds the monopoly for generation and transmission, does not have a strong incentive under such REFITs to purchase a large share of its future energy requirements from RE IPPs. If we consider wind IPPs, for example, the REFIT of 1.25 R/kWh is twice as high as the Standard Average Price in 2012/2013. Since Eskom requested even higher percentage increases, it is not clear whether Eskom tariffs will reach cost recovery levels by 2012/2013. RE looks expensive, against the Standard Average Price.

Particular Implications of the South Africa REFIT Program:Some observations are noteworthy in the above NERSA REFIT calculation methodology:

First, there is no differentiation in tariff levels according to the size of the plant, despite the fact that costs per kWh are higher for small-scale generation facilities. As such, there is a bias in favor of the large-scale projects, encouraging developers to pursue larger projects to achieve the lowest unit costs. This is further ensured by a cut off of 20MW for wind and 1MW for solar PV as a minimum size.

Second, a levelized cost of generation over a 20-year period was used49. This means a single electricity price throughout the project lifetime was applied at level (without inflation adjustments) which would be higher in earlier years than a base price subjected to inflation escalation to amortize the project for the same returns. Table 13 elaborates on the related assumptions. The weakness in this approach is that it does not account for the effect of inflation on debt service and after-tax cash flows. The WACC is a “real” rate that can be applied to costs in constant dollars. Since NERSA assumes a nominal cost of debt of 14.9% and a nominal after-tax return on equity of 25% (Real 17% plus Inflation 8%), the input values would seem to be high enough to attract IPP investment.

Table 13. NERSA assumptions with regard to cost of capitalFinancial parameter Assumption used to

calculate REFITs

49 According to the March 2009 decision, “The FIT were adjusted using the latest publicly available international cost and performance data for RE sources and the screening curves (levelized cost) model of the National Integrated Resource Plan 3.” Screening curves are typically used by a vertically integrated power company (such as Eskom) to optimize the mix of generation sources and the timing of new generation facilities in a long-term plan.

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Debt 70 %Equity 30 %Tax Rate 29 %Inflation 8 %Nominal cost of debt before tax 14.9 %Real cost of debt before tax 6.9 %Nominal return on equity after tax 25.0 %Real return on equity (ROE) after tax 17.0 %Real return on equity (ROE) before tax 23.9 %Weighted average cost of capital (WACC) 12.0 %

Source: www.nersa.org.za

Finally, an unintended consequence of setting tariffs in levelized R/kWh is that the price levels would attract much more foreign investment than is required to meet the IRP targets for 2012 through 2015. This would have further encouraged the use of selection criteria to screen out projects. When South Africa’s REFIT prices are expressed in US cents/kWh they appear higher than in the calculations shown at time of conception (Reasons for Decision documents.) For example, the wind tariff of US cents 12.5 /kWh, (calculated by NERSA based on an exchange rate of R10/US$) translates to US cents 14.7 /kWh by June 2012 exchange rates (R8.5 /US$). This underlines the necessity of stipulating the currency in which contract prices are to be fixed (especially in non-hard currency countries) relative to the currency of the loans raised to finance the projects and the inflation adjustment provisions to apply on REFIT levels. Properly indexed, such windfall profits would neutralize over time through the maintenance of purchasing power parity in exchange rate movements, as a direct result of the differential inflation of the two currencies. A higher levelized price from the outset creates distortions, bypassing these nuances, and costing higher than needed. The point is illustrated on Table 14.

Table 14. REFITs Approved by NERSA in 2009 Tariff

approvedby NERSA

Generationcost

calculatedby NERSA

Generationcost

calculatedby NERSA

Equivalenttariff

at a recentexchange rate

R/kWh R cents /kWh US cents /kWh US cents /kWh

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REFIT Phase I (03.26.09)

Landfill gas methane 0.90 89.6 8.96 10.54Small hydro 0.94 94.0 9.40 11.06Wind 1.25 124.7 12.47 14.67CSP (parabolic w/ storage - 6 hrs/d) 2.10 209.2 20.92 24.61

REFIT Phase II (10.29.09)

Biogas 0.96 96.0 9.60 11.29Biomass solid 1.18 118.0 11.80 13.88CSP (tower w/ storage - 6 hrs/d) 2.31 231.0 23.10 27.18CSP trough w/o storage 3.14 314.0 31.40 36.94PV grid connected (≥1MW) 3.94 394.0 39.40 46.35 Exchange Rate, Rand/US$ 10.00 8.50

With these caveats, however, it must be acknowledged that NERSA has made a positive step toward REFIT calculations by setting rather high REFIT levels with explicit assumptions. This appears to reflect a more technical and less politicized approach to REFIT policy with a view that the amount of RE based MW needed by South Africa is so high that NERSA had no choice but to set high tariffs to attract the necessary level of investor interest.

South Africa’s model has yet to be established. It appears to be heading towards a direction of defining target amounts of RE generating capacity in MW (or annual GWh) and conducting competitive tenders to procure and meet such targets. Although RE targets are set over the long term (20 years) through an IRP, the competitive tendering procedure is short-term (2 years and 9 months). The Minister made a determination that the capacity target of the RE IPP procurement – 3,725MW – is required to ensure the continued uninterrupted supply of electricity50.

The Policy-Adjusted IRP published on May 6, 2011 projected a total of 21,725MW of RE generating capacity additions over the 2010-2030 time frame, of which the technology shares would be: wind 9200MW, solar PV 8100MW, CSP 4300MW landfill gas and small hydro, 125MW. If we assume 25MW for landfill gas (i.e. the RE IPP target) this implies 100MW for small hydro - a very modest target for small hydro relative to the other RE technologies. Import hydro is projected to be 2609MW. The Policy-Adjusted IRP did not propose targets for biomass, biogas, and small generation projects – all of which are included in the RE IPP. The IRP seems to imply that the contribution of biomass, biogas, and small RE will be very modest relative to the contribution of onshore wind and solar PV. In Table 15, the IRP targets are compared with the RE IPP procurement targets. The RE IPP procurement target of 3,725MW was announced in the fall of 201151. It is evident that 18GW of RE capacity remains to be procured, either through

50 Department of Energy, at http://www.ipp-renewables.co.za/index.php/about 51Department of Energy, at http://www.ipp-renewables.co.za/index.php/about. The Terms of Reference: Transaction Advisors to the Government stated at page 6 that “the overall objective of the assignment is to procure at least 1025 MW (different technologies) of RE generated from independent power producers under the REFIT Program.” This target was later revised upward.

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a competitive tender procedure or REFIT. Arguably the Government has more urgent problems to deal with in the power sector, such as financing the Eskom “new build,” defining the future role of the ISMO, and implementing the nuclear build program. However it should be noted that the Bid Submission date for the 5th round of the RE IPP procurement is not far away: August 13, 2013. It is not clear how the additional 18GW will be procured after August 2013.

Table 15. Policy-Adjusted IRP 2010 and RE IPP Procurement TargetsCommitted build New build Committed + New Outside

IRPTotal

Year Wind CSP Landfill

hydro

Sere

Wind

Wind Solar PV

CSP Windtotal

Solar PV

CSP LandfillHydro

MW MW MW MW MW MW MW MW MW MW MW MW MW

201020112012 300 100 100 300 400 100 5002013 400 25 300 400 300 25 7252014 100 400 300 400 300 300 10002015 100 400 300 400 300 300 10002016 400 300 100 400 300 300 10002017 400 300 100 400 300 300 10002018 400 300 100 400 300 300 10002019 400 300 100 400 300 300 10002020 400 300 100 400 300 300 10002021 400 300 100 400 300 300 10002022 400 300 100 400 300 300 10002023 400 300 100 400 300 300 10002024 800 300 100 800 300 300 14002025 1600 1000 100 1600 1000 1000 36002026 400 500 400 500 9002027 1600 500 1600 500 21002028 500 500 5002029 1000 1000 10002030 1000 1000 1000Total 700 200 125 100 8400 8400 1000 9200 8100 4300 125 0 21725 Landfill

HydroBiomassBiogas

RE IPP procurement 1850 1450 200 100 125 3725IRP target less RE IPP 7350 6650 4100 25 n/a 18000

The RE IPP procurement for 3,725MW to ensure uninterrupted supply of power seems to imply an urgent need for additional MW from onshore wind and solar PV projects, and recognition of the fact that lead times for onshore wind and solar PV are normally much shorter than lead times for coal-fired plants. Moreover the emphasis on solar power (1,450MW of solar PV plus 200MW of concentrated solar thermal, in a total portfolio of 3,725MW) would seem to imply that the RE IPP procurement will lead to a further increase in electricity tariffs, despite the fact that there has been considerable political opposition to the tariff increases proposed by Eskom. Although the IRP contains a forecast of the average electricity price through 203052.There may even be greater

52 Department of Energy, Integrated Resource Plan 2010-2030, Appendix C, Figure 9 and Figure 10. The final version of IRP 2010 was published in Staatskoerant, May 6, 2011, although there were several unpublished drafts.

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uncertainty regarding the cost per kWh from nuclear plants and “new build” coal plants (after Kusile and Medupi) than the cost per kWh from RE technologies.

Although the REFIT Program announced by NERSA in 2009 was never implemented as originally proposed, NERSA did publish53 a series of documents required by IPP developers of RE projects to facilitate their understanding of terms and conditions of the REFIT Program. On the contrary, the RFP is available only to prospective bidders who pay a non-refundable fee of 15,000 Rand (roughly US$ 2,000). The RFP must contain the selection criteria, in which “the scoring is divided into 70% price and 30% economic development,” according to a press release issued by the Director General54. The RE IPP procurement website does not identify the Buyer, does not provide a model PPA, and offers no explanation of how the Government will ensure creditworthiness of the offtaker. As a result, the RE IPP procurement program is much less transparent than the REFIT Program originally proposed by NERSA.

Relevance for the Proposed REFIT Program in Namibia:It can be inferred that RE based IPPs would have developed without the RE IPP procurement program or REFIT Program, albeit at a modest pace. At the end of 2009 there were six bagasse-fueled power stations in South Africa with a total capacity of 125MW, all owned by IPPs. Thus, biomass projects were completed before the REFIT Program became effective. Two small hydro plants owned by IPPs, a 3MW facility and a 7MW facility were in operation by August 2009. By July 2009, five wind IPPs had received “project idea” approval from the South Africa Designated National Authority (DNA) within DoE, under the Clean Development Mechanism. Eskom’s proposed 100MW wind farm also received approval55.

The Sere Wind Farm is being developed by Eskom, and its generating capacity (100MW) is large relative to wind projects in sub-Saharan Africa (the exception being the 300MW Lake Turkana Wind Project in Kenya). It is evident that Eskom has not, to date, supported RE based IPP development as strongly as NERSA has. Based on the information available to Nexant it appears that Eskom has not signed a renewable PPA in which the price is based on the REFIT.

Since the power sector of South Africa is very large relative to the power sectors of other countries in Southern Africa, all major initiatives regarding RE development in South Africa will influence the development of the RE industry in sub-Saharan Africa as a whole. However it must be recognized that South Africa is not a “model” for those countries wishing to implement REFIT policies that work, for all the points raised above. 53 The documents issued by NERSA (www.nersa.org.za ) include: South Africa RE Feed-In Tariff (REFIT) : Regulatory Guidelines, March 26, 2009; RE Feed-In Tariff Guidelines, Decision and Reasons for Decision, March 26, 2009; NERSA Consultation Paper: RE Feed-In Tariff Phase II (including a model PPA, as Appendix A), July 15, 2009; RE Feed-In Tariffs Phase II, Decision and Reasons for Decision, October 29, 2009; Rules on Selection Criteria for RE Projects Under the REFIT Programme, February 19, 2010; Notice to Stakeholders, April 4, 2011, announcing that the Grid Connection Requirements for Wind Turbines Connected To Distribution Or Transmission Systems In South Africa had been approved by NERSA and published on its web site. This is a technical document drafted by the RSA Grid Code Secretariat, led by Eskom.54 Department of Energy, Media Statement – 14 November 2011, at http://www.ipp-renewables.co.za/index.php/press/list .55 The GTZ report, December 2009, is a good source of information on the status of all renewable projects, laws, regulations, and economic incentives.

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Arguably, South Africa may become a model for IPP development based on competitive tendering, but the process is too new to have an established track record.

3.3 MAURITIUS REFIT PROGRAM

Scope of the REFIT Program: Mauritius’ installed capacity of 453MW in 2009 consisted of 21% RE and 79% fossil fuels. Fossil fuels, comprising petroleum products and coal, are entirely imported in Mauritius. Given a population of just over 1 million that has nearly 100% access to electricity, RE development is a key policy objective for clean energy as much as it is for import substitution. As such, the 2008 Long Term Energy Strategy approved by the Government of Mauritius aims to increase RE share in the generation mix. RE generation consists of a bagasse based IPP plant (16%) plus hydro (5%) from the Central Electricity Board (CEB), a wholly owned parastatal. Fossil generation includes a coal based IPP (38%) and CEB’s heavy fuel oil and diesel (40%) plus kerosene (0.7%) plants. Total grid-connected generating capacity is 97.5% installed on the island of Mauritius with the rest installed on the island of Rodriguez56.

On December 9, 2010 the Deputy Prime Minister and the Minister of Energy and Public Utilities together announced a Small Scale Distributed Generation Project designed to promote the sale of surplus generation from customer-owned RE (wind, hydro, and solar PV) generation facilities of up to 50 kW in capacity each to the Central Electricity Board (CEB). The cap was a total of 2MW or 200 installations, whichever comes first. A 15 year PPA was offered57. As there is no regulatory authority for the sector, the tariffs and the methodology associated with it was not the subject of any regulatory approval process.

Structure of Tariff: The tariffs were very high by any standard and within five months the program was already oversubscribed with 271 applications representing a total capacity of 3.2MW were received. CEB concluded that among applicants a total representing 2.54MW met the technical requirements and the program was extended in December 2011 by raising the cap to 3MW.

The incremental 1MW was allocated as follows: 540kW of pending requests for wind, hydro, or solar PV 100kW of new requests on Rodriguez for solar PV 360kW of new requests on Mauritius for wind, hydro, or solar PV

The additional 1MW was completely subscribed at some point during 2012, and therefore a notice was published on the CEB web site stating that the 3MW cap had been reached and no

56 UNDP, Project Document: Removal of Barriers to Solar PV Power Generation in Mauritius, Rodriguez and the Outer Islands, pages 5 and 6. 57 This REFIT Program is well documented at http://ceb.intnet.mu/ with the following publications : Central Electricity Board, Grid Code for Small Scale Distributed Generation (SSDG), December 9, 2010; Central Electricity Board, Customer Guidelines for Grid Connection of Small Scale Distributed Generators (SSDG) up to 50 kW, December 9, 2010.

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new applications would be considered. The REFITs approved in December 2010 are shown in the following table.

Table 16. Mauritius Feed-in TariffTechnology Size of facility Feed In Tariff,

Rs/kWhEquivalent in US cent/kWh12.09.2010

Rs29.54/US$

Equivalent in, US cent/kWh03.01.2012

Rs27.73/US$Wind Micro (up to 2.5 kW) 20 67.70 72.10

Mini (2.5 kW< <10 kW) 15 50.80 54.10Small (10 kW< < 50 kW) 10 33.80 36.10

Hydro Micro (up to 2.5 kW) 15 50.80 54.10Mini (2.5 kW< <10 kW) 15 50.80 54.10Small (10 kW< <50 kW) 10 33.80 36.10

Solar PV Micro (up to 2.5 kW) 25 84.60 90.20Mini (2.5 kW< <10 kW) 20 67.70 72.10Small (10 kW< <50 kW) 15 50.80 54.10

Note: Tariffs are reduced by 15%, for any facility where the production to consumption ratio is above 3.

Other tariff indicators

Residential customers >300 kWh/month 8.77 29.70 31.60

Commercial customers 10.01 33.90 36.10

Industrial customers 5.40 18.30 19.50

Particular Implications of the Mauritius REFIT Program:Mauritius does not have an energy regulatory authority, although there is a Ministry of Energy and Public Utilities. CEB is a parastatal company which is vertically integrated and owns oil-fired generating capacity (presumably to be displaced by RE from the REFIT Program).

There is no public document explaining why the REFITs were set at such a high level, as there is no tariff methodology or tariff calculation. Since the flat rate tariff for commercial customers is 10.01 Rs/kWh, it is reasonable to suppose that a REFIT in the range of 8 to 10 Rs/kWh for small wind and small hydro would help RE generation to displace CEB generation from heavy fuel oil and diesel fuel and thereby lower retail tariff levels. However there is no proposal for a “moderate” REFIT, or an estimate of the cost of small wind and hydro generation, or a proposed REFIT for generating facilities larger than 50 kW.

Relevance for the Proposed REFIT Program in Namibia:It can be inferred that neither the Ministry of Energy and Public Utilities nor CEB took the time to calculate the cost of power generation from wind, hydro and solar facilities in Mauritius. As a result, the REFIT was set too high and was oversubscribed. With 79% of the installed capacity dependent on imported fossil fuels, the country’s need for RE generation is clearly much greater

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than 3MW and there is no new program in place to attract investment in RE IPPs. The non-transparent approach resulting in overpricing, the resulting oversubscription, and the consequent closure of the program once its limits were reached, despite the potential to reduce the large import bill on polluting fuels, all underline the need for regulatory scrutiny and more comprehensive planning in setting up a REFIT Program.

3.4 UGANDA REFIT PROGRAM

Scope of the REFIT Program:In 2007 the Electricity Regulatory Authority (ERA) established a REFIT Program in line with the Renewable Energy Policy of Uganda, in order to make modern renewable energy a substantial part of the national energy consumption. ERA set forth feed-in tariffs for two RE sources: hydro power and cogeneration with bagasse, for a period of two years. This REFIT Program, referred to as Phase 1, covered power plants larger than 0.5MW but not exceeding 20MW. In accordance with the Electricity Act of 1999, Uganda Electricity Transmission Company Ltd. (UETC), the holder of transmission license, was assigned by ERA to issue standardized tariffs based on the avoided cost of the system for sales to the grid of electricity generated by RE sources of up to 20MW, as referenced in Table 17.

Table 17. Uganda REFIT Phase 1

Source: Electricity Regulatory Authority of Uganda58

Phase 1 of the REFIT Program had several shortcomings59. The tariff was implemented at a time when the international commodity prices, particularly those of steel and cement, were skyrocketing. The REFIT Program did not have any provision for escalation of prices and was subject to revision after three years. As a result, the tariffs were inadequate to cover the generation costs and guarantee a reasonable return to investors, thus negating the essence of REFIT. At the same time, the REFITs were announced without clear guidelines regarding the selection criteria of projects60.

58 http://www.era.or.ug 59 According to ERA’s Director of Economic Regulation, Benon Mutambi.60 Mutambi, Successfully Regulating Electricity From The Sugar Industry: The Case of Uganda, page 9.

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In January 2011, ERA introduced a revised set of REFITs for eight different technologies, as part of REFIT Program Phase 2. The program has also set priority technologies which may be updated during each REFIT review, as follows:

Priority 1 RE technologies: small hydro power plants, geothermal power plants; bagasse power generation, landfill gas power, biogas, biomass and wind power; and

Priority 2 RE technology: solar PV.

Under Phase 2, the REFIT program applies similarly to Phase 1, to small scale renewable energy systems greater than 0.5MW and up to a maximum installed project capacity of 20MW, pursuant to the Electricity Act of 1999. Any project larger than 20MW must have a PPA negotiated on a case-by-case basis. However, this program offers tariffs for a larger range of RE sources including geothermal, bagasse, detailed hydro tariffs as well as technology specific caps.

Structure of Tariff:Under Phase 2, the tariffs for each technology are set in US$ and are based on the levelized cost of electricity generation from RE sources per kWh. The key assumptions of the tariff calculation for each of the priority technologies that affect the power generation costs are: capital and material costs, grid connection costs, O&M, fuel costs as applicable to biogas and biomass, interest rates on the invested capital and the rate of return for the investors.

The tariff is set according to the year in which the generation license was issued, and is paid for a period of 20 years with O&M costs adjusted on an annual basis for inflation purposes.

Table 18. REFIT Phase 2 Tariffs, O&M and Technology Capacity Limits (2011 – 2014)

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Source: Uganda Electricity Regulatory Authority61

It is worth noting that ERA reserves the right to develop an optional phased tariff structure, allowing a marginal increase at the beginning of the project and a marginal reduction towards the end, while retaining the overall present value.

Particular Implications of the Uganda REFIT Program:It can be inferred that the REFIT Program under Phase 1 did not contribute significantly to the electricity generation from the covered RE sources in Uganda. Particularly so, neither of the co-generation with bagasse projects expanded their power capacity. While the weaknesses of the REFIT program under this phase, as discussed above, added to the slow growth of installed capacity at bagasse power plants, these projects were faced with additional challenges, namely the difficulty of obtaining long-term financing (including the difficulty of raising the equity needed to obtain long-term debt financing) and the difficulty of negotiating connection charges with UETCL. The REFIT Phase 2 tariff for bagasse at 8.1 US cents/kWh is still below the price levels sought by the sugar producers.

Although the REFIT Phase 1 attracted interest from potential RE investors, the avoided cost structure of the tariff became difficult to implement and the adequate avoided cost associated with energy supplied by RE sources could well have been higher than the prices issued in REFIT Phase 1.

Although there is no track record for Phase 2 to date, it appears to be very well designed on the basis of lessons learned from Phase 1, and the tariff levels appear to be reasonable estimates of RE production cost.

Relevance for the Proposed REFIT Program in Namibia:

61 http://www.era.or.ug/Pdf/Approved_Uganda%20REFIT%20Guidelines%20V4%20%282%29.pdf

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Uganda has about five years of experience with REFIT Program implementation. The REFIT Program Phase 2 could provide a model to follow in Namibia, however there are unfavorable aspects of the REFIT structure, such as the absence of capacity size for RE technologies other than hydro, in determining the REFIT level, which need to be remedied in order to successfully motivate a notable development of RE sources under a REFIT Program.

3.5 KENYA REFIT PROGRAM

Scope of the REFIT Program:In 2008 the Ministry of Energy has published Kenya’s Feed-in Tariffs Policy for wind, small hydros and biomass resource generated electricity and the accompanying Feed-in Tariff Guide for Investors. These two documents implement Section 103 of Kenya’s Energy Act which doesn’t mention the feed-in tariffs per se, but it sets forth the Minister’s broad authority so that “the Minister may perform such functions and exercise such powers as may be necessary under this Act to promote the development and use of RE, including but not limited to formulating a national strategy for coordinating research in RE, and providing an enabling framework for the efficient and sustainable production, distribution and marketing of biomass, solar, wind, small hydros, municipal waste, geothermal and charcoal […].”

The policy was further revised in January 2010 and added other renewable energy resources such as geothermal, biogas and solar. This new policy – Feed-in Tariffs Policy on Wind, Biomass, Small Hydro, Geothermal, Biogas and Solar Resources Generated Electricity – and accompanying revised Feed-in Tariffs for RE Resource generated Electricity: Guide to Investors aims at attracting private sector investments in electricity generated from RE sources in order to diversify the national power generation mix, strengthen the national energy security, create employment and generate income.

In a nutshell, the REFIT Program sets out to:

Facilitate resource mobilization by providing investment security and market stability for investors in RE electricity generation;

Reduce transaction and administrative costs by eliminating the conventional bidding process, and

Encourage private investors to operate the power plant prudently and efficiently to maximize the returns.

Structure of Tariff:The tariffs, which include grid connection costs (transmission, substations and associated equipment), are offered in US$ and apply for the economic life of the plant (20 years) as indicated below:

Table 19. Kenya REFIT Tariffs50

Technology Type Plant CapacityMW

Maximum Firm Power Tariff ($/kWh) at the Connection Point

Maximum Non-Firm Power Tariff ($/kWh) at the Connection Point

Geothermal Up to 70 0.085 -Wind 0.5 – 100 0.12 0.12

Biomass 0.5 – 100 0.08 0.06

Small Hydro0.5 – 0.99 0.12 0.10

1 – 5 0.10 0.085.1 – 10 0.08 0.06

Biogas 0.5 – 40 0.08 0.06Solar 0.5 – 10 0.20 0.10

Source: Ministry of Energy, Feed-In Tariff Policy 1st Revision 2010

Under this tariff structure the developer will estimate the cost per kWh of grid connection and will subtract it from the REFIT tariff. If the proposed RE facility is located at a distance far from the grid, the connection cost may render the project uneconomic. Based on these considerations, the tariffs in the table above are not very high. The solar tariff applies only to certain locations in order to supply existing isolated or off-grid power stations, to partly displace the thermal generation. In those cases, where solar power displaces diesel generation, the higher price for solar generated electricity is justifiable.

The calculation of the REFIT tariff is based on the generation cost; it is not adjusted to inflation but it includes the avoided cost of electricity, as an estimation of the current energy cost from a recently procured efficient thermal plant supplying the grid and the least expensive fuel oil (such as heavy fuel oil). The tariffs are set as maximum tariffs not exceeding the price set per kWh of electrical energy supplied to the grid operator at the connection point. Thus for each project the prices will be negotiated with the grid operator on the lower side of the tariff. Additionally tariffs are not differentiated by size with the exception of small hydro generated electricity.

Table 20. Kenya REFIT Tariff for Small Hydro Power Resource Generated ElectricityPower Plant Effective Generation

Capacity (MW)Firm Power Tariff (US cents/kWh) Non Power Tariff (US cents/kWh)

< 1 12.0 101 – 5 10.0 8.0

5 – 10 8.0 6.0Source: Ministry of Energy, Feed-In Tariff Policy 1st Revision 2010

Under the REFIT Program, the tariff shall apply as follows:

Wind: to the first cumulative 300MW capacity of wind power plants with individual plants not exceeding 100MW capacity

Biomass: to the first 200MW of firm power and 50MW of non-firm power with individual biomass power plants not exceeding 100MW capacity

Small hydro: to the first 150MW of firm power and 50MW of non-firm power, with individual small hydro power plants non exceeding 100MW capacity

Geothermal: to the first 500MW of power from geothermal Biogas: to the first 100MW of power from biogas Solar: to the first 100MW of firm power and 50MW of non-firm power from solar

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The cost is a pass-through; the grid operators will recover from electricity consumers 70% of the portion of the feed-in tariff with the exception of solar generated electricity which will be 85%, or as directed by the Energy Regulatory Commission (ERC) at the time of the approval of the PPA or it subsequent review.

At present there are two grid operators: KPLC and KETRACO. Since KETRACO’s mission is to finance and build new transmission lines, it is not clear whether KETRACO is really an Offtaker for RE generation purposes. In the case of Lake Turkana Wind Power, a 300MW project, the Offtaker is KPLC. Although Lake Turkana is too large to qualify for the REFIT Program, its experience would seem to indicate that KETRACO’s role for the foreseeable future is to build transmission lines and not to sign PPAs with RE producers.

Like many African countries, Kenya has a power grid that mainly serves the urban areas (Nairobi and Mombasa) rather than small towns and rural areas. Although KETRACO has an ambitious capital expenditure program, the transmission grid does not yet cover the entire country. Imported hydropower from Ethiopia would play a vital role in enabling KPLC, as system operator, to integrate intermittent power generation such as wind power. However it is still unclear the amount of intermittent generation that can be absorbed by KPLC.

By European standards – for example, in comparison with Germany – Kenya’s REFIT Program is not backed up by a financially strong Offtaker and a well-developed transmission and distribution network and a strategy for integrating intermittent generation. On the other hand, if we consider the quantities and prices (for example, 50MW non-firm biomass power plus 50MW non-firm biogas power at 6 US cents /kWh) it can be inferred that this program will not impose a major burden on KPLC, as primary (or only) Offtaker. Therefore it appears that the Ministry has taken the constraints on RE development – for example, the difficulty of raising end user tariffs, and the impossibility of making KPLC and KETRACO absorb the cost of grid connections - into consideration. Consequently, this is not an ideal REFIT program, and it is not properly structured to attract the investments needed to make advances in RE technology, but it aims instead for a realistic compromise between sociopolitical objectives and “green” policy objectives.

Particular Implications of the Kenya REFIT Program:In Europe and North America the policy objective of REFIT Programs is to promote RE generation and find ways to integrate it into the power system, rather than promote “firm” RE generation and discourage “non-firm” generation. This is understandable, since both wind power and solar power are intermittent resources, and the cost of adding energy storage to a solar facility is substantial.

In Kenya, however, the tariffs for RE generation are differentiated for firm and non-firm power. Without defining what constitutes firm and non-firm power, the grid system operator evaluates the firmness of power generated from RE, other than wind and geothermal power, at the time of PPA negotiations and can impose a price penalty on the non-firm portion of the project output. The tariff difference is 2 US cents/kWh for small hydro, biomass, and biogas, and 10 US cents/kWh for solar. Since Kenya’s REFIT price for non-firm biomass and biogas power is only 6 cents/kWh, the incentive offered to the investor is weak; whether this price level should be

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considered a “subsidy” depends on the short-run marginal cost of the generation or imported energy that is displaced by non-firm biomass and biogas generation. In addition, there is no evidence whether the 2 US cents/kWh price difference is based on costs. Nexant’s understanding of the price difference is that it is not cost-based, and it is intended to give the grid system operator an opportunity to impose a penalty on biomass, biogas, and small hydro projects for which the power is not dispatchable. If the facility offers some level of base load generation, that portion of the output would receive the firm power price, while all the rest would receive the non-firm power price.

In the case of geothermal resources the REFIT covers individual projects whose effective generation capacity will not exceed 70MW subject to a ceiling of 500MW as described above. By Kenya’s standards this represents “small geothermal,” and it complements a policy of government investment in geothermal power production. In this regard, the Geothermal Development Company (GDC), a government-owned company formed in 2009 to build and operate geothermal power plants, set out a ten-year plan to generate at least 3,000MW of capacity from geothermal resources, and at least 5,000MW by 2030. Therefore, the 500MW set out under the REFIT Program will play a relatively minor role, should GDC achieve its target capacity.

Relevance for the Proposed REFIT Program in Namibia:Kenya appears to have a well-defined REFIT policy from a legal and regulatory standpoint. In 2011 two PPAs had been already signed under the REFIT program. However, there are weaknesses in its program such as the separation of power output in firm and non-firm; the lack of clarity regarding recovery of RE generation costs by the offtakers through end-user tariffs and the imposition of the obligation to purchase RE generation being placed on the grid system operator, although such obligation does not generally pertain to system operation. Instead, Kenya’s REFIT program should have a tariff framework in which the obligation to purchase electricity from RE sources is included in the tariff collected by the system operator and not the distribution company. In light of these considerations, the REFIT program of Kenya falls short from becoming an ideal model to emulate for Namibia.

3.6 ETHIOPIA REFIT PROGRAM

Scope of the REFIT Program:In 2009 the Ethiopian Electric Agency has drafted a Feed-in Tariff Proclamation – Third Draft setting out tariff levels for firm and non-firm power from small hydro, biomass, wind and geothermal sources. The objective of the draft law is to set the tariff rates for IPPs who can generate electricity from RE resources such as hydropower plants, biomass, geothermal and wind power, excluding solar power. The Government of Ethiopia recognizes the importance to adopt a legal framework that guarantees a level of tariff that will make RE resources financially and economically attractive. The Tariff Proclamation is intended to encourage the diversification of the power mix in the national grid and is expected to provide investment security and market stability for private investors in electricity generation from these resources. The act is currently under public consultations and the Ministry of Water and Energy is collecting all inputs from relevant stakeholders.

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Structure of Tariff:There are different tariffs for firm power and non-firm power from small hydro, biomass, and geothermal power. The draft Proclamation defines firm energy as the power or power-producing capacity, intended to be available at all time during the period covered by a guaranteed commitment to deliver. The difference between “firm” and “non-firm” is not based on an estimate of production cost; it simply represents a penalty of 2 US cents/kWh applied to non-firm power. For wind power the difference in tariffs is related to the fact that a lower average annual wind speed will result in a lower capacity factor and therefore higher costs per kWh, but the fact that the REFIT difference is 1 US cent/kWh, regardless of project size, implies that this is not based on an estimate of production cost. The Proclamation does not define the period covered by a guaranteed commitment, or the type of guarantee offered; if the project offers some level of capacity that is available at all times during peak hours of the peak season, for example, generation up to that capacity level would receive the firm power price. For hydro resources the concept of “guaranteed commitment” would have to be defined in the PPA, for example with regard to a 90 or 95 percent probability level based on historical data on water inflows. In the case of geothermal power it is not clear why would a developer design a plant to produce non-firm power; the international best practice is to find and develop geothermal resources that are stable and predictable.

Particular Implications of the Ethiopia REFIT Program: According to the latest Draft of “Scaling-Up Renewable Energy Program Ethiopia Investment Plan”62 published by the Ministry of Water and Energy in January 2012, the Government aims at capping generation from renewable resources at 300MW and the RE project size at 40MW. It is further indicated that in case the RE feed-in tariff is not high enough, the gap between the approved tariff and the technology transfer would be financed via subsidies to the Ethiopian Electric Power Corporation – the national power utility company. At this stage the focus of the proposed REFIT program is placed on the development of hydroelectric, geothermal and wind power projects that would concur with the National Climate Resilient Green Economy Initiative to develop 2.5GW of renewable energy by 2030 including 22,000MW of hydropower, 1,000MW of geothermal, and 2,000MW of wind. Plans are underway to replace conventional thermal generators with renewable energy generators which will help the countries that import electricity from Ethiopia receive additional benefits through carbon credits.

Relevance for the Proposed REFIT Program in Namibia:Ethiopia has yet to implement the proposed REFIT Program. In the meantime, the projected REFIT levels are set too low compared with South Africa and Kenya, and they are most likely too low to attract private sector investment in some of the size categories and/or RE technologies. For example, a wind farm with 25 to 40MW capacity and wind speed less that 7.5 m/s has a REFIT of only 5 US cents/kWh. Furthermore it is not clear how the cost of RE generation will be recovered by the grid system operator. In light of these considerations, it may

62 http://www.epa.gov.et/Lists/News/Attachments/17/SREP%20Ethiopia%20Investment%20Plan%20-%20Version %20for%20External%20Review%20-%20January%202012.pdf

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be premature to assess whether the proposed REFIT program will be a model to follow in Namibia until such program is implemented and passed into law.

Table 21. Ethiopia Proposed REFITs

TechnologySizeMW

Firm energy, c/kWh

Non-firm energy, c/kWh

All energy, c/kWh

Wind speed

<7.5 m/s

Wind Speed

≥7.5 m/sHydropower

≥ 0.1 and ≤ 0.5 8.0 6.0> 0.5 and ≤ 2.5 7.5 5.5> 2.5 and ≤ 5 7.0 5.0> 5 and ≤ 10 6.5 4.5

> 10 and ≤ 25 6.0 4.0> 25 and ≤ 40 5.5 3.5

Biomass

> 0 and ≤ 0.5 10.0 8.0> 0.5 and ≤ 2.5 9.5 7.5> 2.5 and ≤ 5 9.0 7.0> 5 and ≤ 10 8.5 6.5

> 10 and ≤ 25 8.0 6.0> 25 and ≤ 40 7.5 5.5

Wind

≥ 0.2 and ≤ 0.5 10.0 9.0> 0.5 and ≤ 2.5 9.0 8.0> 2.5 and ≤ 5 8.0 7.0> 5 and ≤ 10 7.0 6.0

> 10 and ≤ 25 6.0 5.0> 25 and ≤ 40 5.0 4.0

Geothermal

≥ 0.5 and ≤ 2.5 10.0 8.0> 2.5 and ≤ 5 9.5 7.5> 5 and ≤ 10 9.0 7.0

> 10 and ≤ 25 8.5 6.5> 25 and ≤ 50 8.0 6.0

Bagasse

≥ 0.1 and ≤ 0.5 10.0> 0.5 and ≤ 2.5 9.0> 2.5 and ≤ 10 8.0> 10 and ≤ 15 7.0> 15 and ≤ 25 6.0> 25 and ≤ 40 5.0> 40 and ≤ 50 4.0

Coal, oil shale, gas

≥ 0.5 and ≤ 5 6.0

> 5 and ≤ 10 5.0> 10 and ≤ 40 4.0

3.7 RWANDA REFIT PROGRAM

Scope of the REFIT Program:Nexant has designed the Renewable Energy Feed-In Tariff in Rwanda which was announced earlier this year by Rwanda Utilities Regulatory Agency (RURA). The REFIT Program was adopted for hydro power plants of minimum 50kW and maximum 10MW capacity and it follows the same methodology as described in this Paper.

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Structure of Tariff:The tariff methodology was designed for the purchase of energy by the Energy Water and Sanitation Authority (EWSA), as Offtaker, from micro-hydro, geothermal, solar PV and wind power generation projects with a maximum capacity size of 10MW. The REFIT in Rwanda was developed on a cost recovery plus return basis to encourage the participation of IPPs in the development of RE projects in the country. The tariff calculated an energy rate to be paid per unit of generation in a given size range, between 10kW and 10MW, and a given RE resource, that would cover the costs and provide an acceptable rate of return for the generation facility without the use of subsidies, grants or similar concessionary credits.

The REFIT, together with a supporting regulatory framework, was adopted for a period of 3 years and it applies to projects that are located within 10km from the grid at the time the PPA is signed without any penalty or reward for such distance. The transmission connection costs associated with the REFIT are structured as a pass-through cost to the end consumers.

Table 22. Published REFITs Rwanda

Source: REFIT Regulations February 2012 – RURA

Particular Implications of the Rwanda REFIT ProgramAs Rwanda advances the development of the micro-hydro resources, it will be critical to identify the larger size hydro projects that will produce the most electric energy at the lowest tariff and develop such plants first. Presently, an estimated 80% of the 333 micro-hydro sites are less than 100kW and account for an average 15% of the total overall capacity. Similarly, wind power development can take off quite swiftly. However, the situation is more challenging for the development of geothermal and solar generation under a REFIT Program in Rwanda. Geothermal development is less attractive than other renewable energy sources because it requires a substantial financial investment to find and prove its availability. Consequently, geothermal will take a longer time to come on stream and its impact on the RE mix in the first three years of the REFIT Program will be small relative to its potential and perhaps limited to pilot scale projects. In the case of solar generated electricity, the capital costs for on-grid development are significantly high; however there may be potential for solar generated

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electricity potential in remote off-grid areas where the avoided cost of electricity is equal to that of diesel.

Relevance for the Proposed REFIT Program in Namibia:The proposed REFIT Program in Namibia was designed using a comparable tariff methodology and regulatory framework as adapted to the RE potential and viability of sources in the country.

3.8 SUMMARY COMPARISON

In summary, the benchmarks described above offer relevant examples of private sector mobilization through REFIT programs in Sub-Saharan African countries. In order to become a successful model to emulate in Namibia, a REFIT program needs to achieve an effective integration of RE technologies in the energy generation mix by enabling the IPPs development beyond the cost-plus-return methodology and by ensuring a predictable transaction environment with the Offtaker in all contractual matters of a PPA for viable RE projects.

In Tanzania the REFIT Program is based on estimates of avoided cost of the system with a large spread between the price offered for producers connected to the main grid and the price offered to producers connected to small, isolated networks. The Program is not a model for the REFIT in Namibia but it should provide useful lessons with regards to rural electrification based on generation from small hydro and biomass.

Similarly, a model is yet to be established in South Africa. The REFIT program is rather a hybrid between competitive tendering and Feed-in Tariffs. However, the power sector of the country is very large as compared to other countries in Southern Africa, therefore all major initiatives regarding RE development in South Africa will most likely influence the development of the RE industry in the sub-Saharan region as a whole. Presently, South Africa is not a model for Namibia as regards the adoption of a REFIT Program because: (a) there is no differentiation in tariff levels according to the size of the plant, despite the fact that costs per kWh are higher for small-scale generation facilities; consequently there is a bias in favor of the large-scale projects, encouraging developers to pursue larger projects to achieve the lowest unit costs; (b) there is a single electricity price throughout the project lifetime applied without inflation adjustments at a level which would be higher in earlier years than a base price subjected to inflation escalation to amortize the project for the same returns; consequently the effect of inflation is not accounted on the debt service and after-tax cash flows; and (c) the tariffs are set in levelized R/kWh so that the price levels would attract much more foreign investment than is required to meet the country’s IRP targets for 2012 through 2015.

In Mauritius the REFIT Program was set out without a tariff calculation methodology which resulted in overpricing the cost of power generation from RE sources, an oversubscription of the program and an imminent closure of the REFIT once its overtly low limits set at 3MW have been reached. In this case, the lesson to draw is that an effective REFIT program must be supported by transparent regulatory scrutiny and a comprehensive planning in setting up the tariffs.

Uganda has experimented with the REFIT program in a two-phase approach by initially setting out tariffs only for hydropower and cogeneration with bagasse for a designated project size that

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would not exceed 20MW. The avoided cost structure of the tariff failed to mobilize the private sector to develop additional generation capacity from RE sources. Subsequently, the Government has built upon the weaknesses of this approach and has come up with a better structured tariff methodology in Phase 2, based in the production cost of RE, and has added six RE sources to the generation mix. This phase is yet to demonstrate its merits whether it can successfully generate an effective development of RE sources.

In the same way Kenya appears to have a well-defined REFIT policy from a legal and regulatory standpoint. Nonetheless, the program is not short of challenges because it separates the power output into firm and non-firm, it lacks clarity over the recovery of RE generation costs by the offtaker through end-user tariffs and, as an out of the ordinary industry practice, it imposes the obligation to buy on the system operator.

Ethiopia has no demonstrated track record in adopting a REFIT Program to date. The proposed tariffs are set too low compared with South Africa and Kenya, and they are most likely too low to attract private sector investment in some of the RE technologies.

Lastly, Rwanda has recently adopted a REFIT Program for microhydro power plants of up to 10MW based on a cost-plus-return methodology and it can be inferred that it is the most relevant REFIT Program model to emulate for Namibia to date.

In view of the above, the proposed REFITs for Namibia are comparable to those available in other countries. However, it is worth noting that, with the exception of Rwanda, the REFIT tariffs available in the benchmarked countries are not as fine-tuned per energy resource and capacity size and may also differ in the assumptions used.

The REFIT for solar PV generation for 10-250kW at 0.480 US$/kWh is almost identical with Rwanda’s US$ 0.489/kWh and slightly below Mauritius’ US$ 508/kWh.

Namibia’s REFIT for solar PV generation range for 250kW - 2MW is above the available tariffs in Tanzania, Uganda and Kenya and slightly below the proposed tariff in Rwanda for the same capacity size.

Solar PV generation between 2 – 5MW Namibia’s REFIT is below Rwanda, Uganda and South Africa’s tariffs and comparable to Uganda’s. Similarly, solar PV generation larger than 5MW is below the tariff rates of South Africa, Uganda and Rwanda.

Wind generation larger than 250kW is relatively higher than the REFIT tariffs in Uganda, Kenya, Ethiopia and Rwanda.

Wind generation ranging between 250kW – 2MW is relatively higher compared to the other benchmarks and similarly so for projects above 5MW.

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Table 23. Namibia REFIT ComparisonBase Size

MWNamibiaROE 20%

NamibiaIRR 16%

Tanzania63

South Africa64

Mauritius65 Uganda Kenya66 Ethiopia67 Rwanda68

ROE 20%RwandaIRR 16%

Biomass0.25 - 0.5MW 0.221 0.184 N/A N/A N/A N/A N/A N/A N/A N/A

0.5 - 5MW 0.146 0.127 N/A N/A N/A N/A N/A N/A N/A N/A

5 <10MW 0.105 0.095 N/A N/A N/A N/A N/A N/A N/A N/A

Solar

< 10kW 0.440 0.333 N/A N/A 0.677 N/A N/A N/A 0.513 0.39810 - 250kW 0.421 0.319 0.250 N/A 0.508 N/A N/A N/A 0.489 0.379250-2MW 0.376 0.285 0.250 N/A N/A

0.362 0.100 -0.200N/A

0.444 0.3452 - 5MW 0.304 0.247 0.250 0.580 N/A

0.362 0.100 - 0.200N/A

0.375 0.3095 <10MW 0.269 0.231 0.250 0.580 N/A

0.362 0.100 - 0.200N/A

0.357 0.309

Wind

<10kW 0.248 0.189 N/A N/A 0.508 N/A N/A N/A 0.235 0.18310-250kW 0.228 0.174 0.080 n/a 0.33869 N/A N/A

0.090 -0.100 0.214 0.166250 - 2MW 0.160 0.122 0.080 n/a N/A

0.124 0.120 0.080 - 0.090 0.147 0.1142 - 5MW 0.138 0.112 0.080 n/a N/A 0.124 0.120 0.070 -0.080 0.124 0.1025 <10MW 0.126 0.108 0.080 0.180 N/A

0.124 0.120 0.060 - 0.070 0.118 0.102

63 Project sizes ≤10 MW. The REFIT shown here for Solar is the SPP tariff for small isolated networks. 64 Converted from Rand/kwh at Dec 12, 2010 exchange rate. Wind ≥20 MW and Solar ≥1 MW65 Equivalent in US cent/kWh December 9, 2010, Rs29.54/US$66 Solar and Wind >0.5 MW.67 Wind ≥0.2 MW68 Calculated in 201169 Up to 50kW only.

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Section 4 Assumptions

Capital Costs: Nexant developed the projected cost data for Namibia for typical renewable biomass, solar and wind energy projects based on Nexant’s analysis of the inventory of such generation projects and prospective sites as provided by ECB, the recipient of all applications for energy generation licenses.

The biomass data provided for the 250kW CBEND project was analyzed for capital and operating expenses which were compared to comparable size power plants from energy industry publications, Nexant’s data base and data from the Energy Information Administration of the US Department of Energy.

The solar PV cost data regarding Innowind, Econam and Momentus Energy projects was reviewed and analyzed as a starting point in the development of capital and operating expenses. Further on, these projects were compared to Nexant’s data base for solar PV and the appropriate capital costs were developed for each range of plant size. Similarly, the Aeolus, Electrawind and Innowind energy projects represented the starting point in the development of capital expenses for five ranges of wind facilities asserted in the cost analysis. Since all the wind cost data collected in Namibia was for projects larger than 40MW, Nexant established costs per kW factors and compared this data to EIA and Nexant’s data base figures for the size ranges under consideration. Nexant factored all of the CAPEX data based upon the local construction material, equipment cost, and the cost of available local labor according to the data collected in Namibia.

Nexant did not include solar CSP in our capital cost analysis for the REFIT. The data available on the Welwistchia Solar CSP project revealed a very high CAPEX cost of US$ 7,856/kW for a 22MW power plant. In general, CSP projects do not lend themselves to small sized projects, as these must take advantage of economies of scale to reduce the cost per kW. CSP technology starts to become competitive in the 150-300MW range, with storage to extend operational hours.

Civil Works Materials: Reinforcing steel, steel plate, piping, and structural steel shapes will be purchased outside of Namibia. Cement, sand and stone required for concrete will be sourced in Namibia.

Construction Equipment: All large construction equipment will be leased and/or purchased for the project from sources outside of Namibia.

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Table 24. Renewable Base Case Capital Cost (CAPEX) Data

Technology SizeTerm of Loan

Construction Period % Year 1 % Year 2

Civil Works

USDEquipment

USD

DevelopmentUSD

Effective MW

Opex as % of

CapexBase Cost

$US

Base Cost

$US/kWBio-Mass 0.25 - 0.5MW 6 2 67% 33% 319,600 896,860 42,960 0.25 8.65% 1,259,420 5,038Bio-Mass 0.5 - 5MW 8 2 67% 33% 2,584,700 6,558,300 457,150 2.75 8.65% 9,600,150 3,491Bio-Mass 5 <10MW 10 2 60% 40% 4,284,090 10,789,560 753,650 6 8.65% 15,827,300 2,638Bio-Mass 5 <10MW (REPEAT) 10 2 60% 40% 4,284,090 10,789,560 753,650 6 8.65% 15,827,300 2,638Solar < 10kW 5 1 100% 0 21,065 132,874 8,102 0.05 2.00% 162,041 3,241Solar 10 - 250kW 5 1 100% 0 40,300 254,200 15,500 0.1 2.00% 310,000 3,100Solar 250 - 2MW 5 1 100% 0 153,042 965,345 58,863 0.425 2.00% 1,177,250 2,770Solar 2 - 5MW 7 1 100% 0 1,042,080 6,573,120 400,800 3.34 2.00% 8,016,000 2,400Solar 5 <10MW 9 1 100% 0 1,953,900 12,324,600 751,500 6.68 2.00% 15,030,000 2,250Wind < 10kW 5 1 100% 0 67,200 160,800 12,000 0.1 2.50% 240,000 2,400Wind 10 - 250kW 5 1 100% 0 154,000 368,500 27,500 0.25 2.50% 550,000 2,200Wind 250 - 2MW 5 1 100% 0 434,000 1,038,500 77,500 1 2.50% 1,550,000 1,550Wind 2 - 5MW 7 1 100% 0 1,197,000 2,864,250 213,750 3 2.50% 4,275,000 1,425Wind 5 <10MW 9 1 100% 0 2,310,000 5,527,500 412,500 6 2.50% 8,250,000 1,375

Construction Period: This varies by project technology and size, as follows: Biomass projects are assumed to be completed within 2 years. Solar and wind projects are assumed to be completed within 1 year.

Consumables: Construction consumables, such as oil, gasoline, water, temporary electrical power, construction camp facilities and local transportation will be obtained on the local market in Namibia.

Table 25. Length of Construction and Loan Term

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Technology SizeTerm of Loan

Construction Period % Year 1 % Year 2

Bio-Mass 0.25 - 0.5MW 6 2 67% 33%Bio-Mass 0.5 - 5MW 8 2 67% 33%Bio-Mass 5 <10MW 10 2 60% 40%Bio-Mass 5 <10MW (REPEAT) 10 2 60% 40%Solar < 10kW 5 1 100% 0Solar 10 - 250kW 5 1 100% 0Solar 250 - 2MW 5 1 100% 0Solar 2 - 5MW 7 1 100% 0Solar 5 <10MW 9 1 100% 0Wind < 10kW 5 1 100% 0Wind 10 - 250kW 5 1 100% 0Wind 250 - 2MW 5 1 100% 0Wind 2 - 5MW 7 1 100% 0Wind 5 <10MW 9 1 100% 0

Corporate Tax Rate: It is set at 35%. Losses can be deferred into future years for tax purposes. Taxes affect cash flows for ROE calculations, but not project cash flows for IRR calculations.

Debt Service Coverage Ratio: A minimum of 1.3 is maintained at all times. The ratio is calculated adding Net Income plus Annual Interest plus Depreciation plus Debt Service Reserve Account all divided by Annual Interest and Principal Repayment.

Debt Service Reserve Account: Accumulates principal plus interest due over next 6 months. Note Model shows annual payments for debt service (to simplify calculations), but assumptions for Reserve Account and LIBOR rate, which impact costs, are for semi-annual payments.

Debt to Equity Ratio: This is set at 75:25 with 75% of the project financed by loans and the remaining 25% by equity of the project sponsors.

Depreciation: Fixed assets are depreciated using straight line depreciation. Depreciation affects taxes in cash flows for ROE calculations. It does not affect project cash flow IRR calculations.

Electrical Equipment and Materials: All electrical generation and control equipment including cables, wiring, conduit, disconnect switches, transformers and lighting fixtures will be purchased outside of Namibia.

Engineering and Design: The CAPEX costs include detailed plant engineering and design costs but do not include feasibility study and project development costs.

Exchange Rate: The calculations use 7 NAD for 1 USD based on the 2012 average exchange rate.

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Financial Projections: These are made in current USD terms, with REFIT results presented in $/kWh.

Connection/ Transmission: No costs associated with connection/ transmissions of power from the power plant project are included in the tariff. Power is supplied at the high side of the plant’s step-up transformer and plant power metering is not included.

Interest during Construction: 7.50% on average drawdown plus 1% on average undisbursed amount plus 1% on initial loan amount.

Land: Provided by the Government at no cost (Regulations address variations at additional compensation.)

Loans: These comprise 75% of all project costs for each project. Principal and interest repayment are reflected in ROE calculations, not in project cash flow IRR calculations. They are denominated in US$ and have the following terms:

Grace Period: construction period rounded up to next full year. Principal Repayment Period (taking mid-points of size ranges):

o Projects < $6.5 million Total Required Financing: 4 years(applies to <0.5MW Bio-mass; <2MW Solar and Wind)

o Projects $6.5< <$10.0 million and Total Required Financing: 6 years(applies to 0.5-5MW Bio-mass; 2-5MW Solar and Wind)

o Projects > $10.0 million Total Required Financing: 8 years (applies to 5< all Resource Bases)

Principal Installments: equal annual principal repayments during repayment period. Interest Rate: 7.5% per annum assumed to be the fixed rate swap equivalent of 6-month

LIBOR+600 basis points, as the rate of an above average risk project in Namibia as a BBB- (by Fitch, Baa3 by Moody’s) rated country for its sovereign foreign currency debt.

Loan Commitment Fee: 1% paid on undisbursed amount of loan. Front End Fee: 1% for the total loan amount.

Mechanical Equipment: The assumption is that all mechanical equipment will be purchased outside of Namibia.

Operating Costs (OPEX): It is set at % of CAPEX for the Base Case, as follows: 8.65% of CAPEX for Bio-mass (includes a 1.15% fuel charge) 2.5% of CAPEX for Wind 2% of CAPEX for Solar

Physical Contingency: For each project, a physical contingency increasing capital costs by 5% is assumed to reflect unexpected CAPEX.

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Price Contingency: Financial projections are made in current US$ terms. To do so, inflation assumptions must be made for local and foreign procured CAPEX and OPEX as well as revenue.

2.5% inflation applies to Foreign CAPEX (direct and indirect) during the first year of construction, and to all costs and during the second year of the analysis and thereafter;

6.3% annual inflation is applied to all local costs during the first year of construction, even though they are denominated in US$ for the projections, on the assumption that it takes a full year for local inflation to work its way through the exchange rate which lags in adjusting for differential inflation between the two currencies.

Civil Works are assumed as local costs. Equipment is assumed as a foreign cost. Development is assumed to be an 88% foreign cost and 12% local cost. 2.5% annual inflation rate in US$ applies throughout the REFIT Model to post

construction OPEX and to revenues, but not to debt payment. REFITs are assumed to increase annually with inflation in current US$.

Project Life: All projects are assumed to have a 20 year useful life70 of operation before they are completely rehauled. In reality, different assets in the project would have different useful lives and would undergo refurbishment over and beyond regular maintenance, so that the plant can operate seamlessly and continue operating well beyond 20 years. However, for modeling purposes, it is acceptable approximation to assume an average life, provide the regular maintenance as included in OPEX, and forego the refurbishment expenditures on condition that revenues are also foregone after the assumed average useful life of the plant altogether.

Size Categories: Five different categories are identified for which REFITs is calculated per resource base as follows:

< 10 kW 10 – 250 kW 250 kW – 2MW 2 – 5MW, and 5 < 10MW.

Salvage Value: The project’s value at the end of the 20 year Project Life is assumed zero.

Spare Parts: The cost of operating spare parts for the power projects and their storage are included in the OPEX costs.

Short-term Interest Earned: 3% on outstanding Reserve Accounts.

Short-term Interest Paid: 5% on outstanding Working Capital.

70 Note that there is no significant impact on electricity price if project useful life is extended to 25 years since, at a discount rate of 20%, US$1 million revenue has a Net Present Value of about US$18,000 if received in year 22 (including 2 years construction) as opposed to about US$7,000 in year 27.

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Working Capital: This being Current Assets minus Current Liabilities, it assumes one month of annual OPEX (8%) as Cash plus two weeks of annual Revenue (4%) as Accounts Receivable plus one quarter of annual OPEX (25%) as Inventory plus half the annual Debt Service as the Cash in the Debt Service Reserve Account to equal Current Assets and one month of annual OPEX as Accounts Payable.

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Section 5 Summary of Inputs for REFIT Calculations by Technology Type

Technology SizeTerm of Loan

Construction Period % Year 1 % Year 2

Civil Works

USDEquipment

USD

DevelopmentUSD

Effective MW

Opex as % of

CapexBase Cost

$US

Base Cost

$US/kWBio-Mass 0.25 - 0.5MW 6 2 67% 33% 319,600 896,860 42,960 0.25 8.65% 1,259,420 5,038Bio-Mass 0.5 - 5MW 8 2 67% 33% 2,584,700 6,558,300 457,150 2.75 8.65% 9,600,150 3,491Bio-Mass 5 <10MW 10 2 60% 40% 4,284,090 10,789,560 753,650 6 8.65% 15,827,300 2,638Bio-Mass 5 <10MW (REPEAT) 10 2 60% 40% 4,284,090 10,789,560 753,650 6 8.65% 15,827,300 2,638Solar < 10kW 5 1 100% 0 21,065 132,874 8,102 0.05 2.00% 162,041 3,241Solar 10 - 250kW 5 1 100% 0 40,300 254,200 15,500 0.1 2.00% 310,000 3,100Solar 250 - 2MW 5 1 100% 0 153,042 965,345 58,863 0.425 2.00% 1,177,250 2,770Solar 2 - 5MW 7 1 100% 0 1,042,080 6,573,120 400,800 3.34 2.00% 8,016,000 2,400Solar 5 <10MW 9 1 100% 0 1,953,900 12,324,600 751,500 6.68 2.00% 15,030,000 2,250Wind < 10kW 5 1 100% 0 67,200 160,800 12,000 0.1 2.50% 240,000 2,400Wind 10 - 250kW 5 1 100% 0 154,000 368,500 27,500 0.25 2.50% 550,000 2,200Wind 250 - 2MW 5 1 100% 0 434,000 1,038,500 77,500 1 2.50% 1,550,000 1,550Wind 2 - 5MW 7 1 100% 0 1,197,000 2,864,250 213,750 3 2.50% 4,275,000 1,425Wind 5 <10MW 9 1 100% 0 2,310,000 5,527,500 412,500 6 2.50% 8,250,000 1,375

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Section 6 REFITs by Technology Type

The following tables are based on the ROE approach for the REFIT. A separate table is shown for each technology type and size. For each post-tax ROE value of 16%, 20% and 24% the corresponding pre-tax IRR and revenue per kw year, at base CAPEX and OPEX values are also reported as follows:

REFITs : ROE driven Revenue Requirement Calculation - Equity Cash Flow ROE (post-tax) and Project Cash Flow IRR (pre-tax)

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 75% 0.223 0.237 0.208 0.245 0.261 0.228 0.201 0.214 0.187 Project Pre-tax IRR - Base Capex/Opex 17.79% 85% 0.196 0.210 0.183 0.216 0.230 0.201 0.177 0.189 0.165 Rev $/kWy 1,463 95% 0.176 0.187 0.164 0.193 0.206 0.180 0.158 0.169 0.148 Post-tax ROE 20% 75% 0.251 0.266 0.236 0.276 0.292 0.259 0.226 0.240 0.213 Project Pre-tax IRR - Base Capex/Opex 21.04% 85% 0.221 0.234 0.208 0.243 0.258 0.229 0.200 0.211 0.188 Rev $/kWy 1,649 95% 0.198 0.210 0.186 0.218 0.230 0.205 0.179 0.189 0.168 Post-tax ROE 24% 75% 0.279 0.294 0.265 0.307 0.323 0.291 0.252 0.265 0.238 Project Pre-tax IRR - Base Capex/Opex 24.09% 85% 0.246 0.259 0.233 0.271 0.285 0.256 0.222 0.234 0.210 Rev $/kWy 1,835 95% 0.220 0.232 0.209 0.242 0.255 0.229 0.199 0.209 0.188

Bio-Mass 0.25 - 0.5MWCAPEX Base case CAPEX + 10% CAPEX -10%

67

Capacity Factor

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 75% 0.148 0.159 0.138 0.163 0.174 0.152 0.134 0.143 0.125 Project Pre-tax IRR - Base Capex/Opex 16.77% 85% 0.131 0.140 0.122 0.144 0.154 0.134 0.118 0.126 0.110 Rev $/kWy 975 95% 0.117 0.125 0.109 0.129 0.138 0.120 0.106 0.113 0.098 Post-tax ROE 20% 75% 0.165 0.175 0.155 0.182 0.193 0.170 0.149 0.158 0.140 Project Pre-tax IRR - Base Capex/Opex 19.64% 85% 0.146 0.155 0.137 0.160 0.170 0.150 0.131 0.140 0.123 Rev $/kWy 1,086 95% 0.130 0.139 0.122 0.143 0.152 0.134 0.118 0.125 0.110 Post-tax ROE 24% 75% 0.182 0.192 0.172 0.200 0.211 0.189 0.164 0.173 0.155 Project Pre-tax IRR - Base Capex/Opex 22.34% 85% 0.161 0.170 0.152 0.176 0.186 0.167 0.145 0.153 0.137 Rev $/kWy 1,196 95% 0.144 0.152 0.136 0.158 0.167 0.149 0.130 0.137 0.122

Bio-Mass 0.5 - 5MWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 75% 0.108 0.116 0.100 0.119 0.127 0.110 0.097 0.104 0.090 Project Pre-tax IRR - Base Capex/Opex 15.95% 85% 0.095 0.102 0.088 0.105 0.112 0.097 0.086 0.092 0.080 Rev $/kWy 709 95% 0.085 0.091 0.079 0.094 0.100 0.087 0.077 0.082 0.071 Post-tax ROE 20% 75% 0.119 0.127 0.111 0.131 0.139 0.122 0.107 0.114 0.100 Project Pre-tax IRR - Base Capex/Opex 18.56% 85% 0.105 0.112 0.098 0.115 0.123 0.108 0.095 0.101 0.088 Rev $/kWy 781 95% 0.094 0.100 0.088 0.103 0.110 0.096 0.085 0.090 0.079 Post-tax ROE 24% 75% 0.130 0.138 0.122 0.143 0.151 0.134 0.117 0.124 0.110 Project Pre-tax IRR - Base Capex/Opex 21.02% 85% 0.115 0.121 0.108 0.126 0.133 0.118 0.103 0.109 0.097 Rev $/kWy 854 95% 0.103 0.109 0.097 0.113 0.119 0.106 0.092 0.098 0.087

CAPEX Base case CAPEX + 10% CAPEX -10%Bio-Mass 5 <10MW

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 15% 0.503 0.514 0.492 0.553 0.565 0.541 0.454 0.463 0.444 Project Pre-tax IRR - Base Capex/Opex 18.66% 20% 0.377 0.386 0.369 0.415 0.424 0.406 0.340 0.348 0.333 Rev $/kWy 661 25% 0.302 0.309 0.295 0.332 0.339 0.325 0.272 0.278 0.266 Post-tax ROE 20% 15% 0.587 0.598 0.576 0.645 0.657 0.633 0.529 0.539 0.519 Project Pre-tax IRR - Base Capex/Opex 22.30% 20% 0.440 0.449 0.432 0.484 0.493 0.475 0.397 0.404 0.389 Rev $/kWy 771 25% 0.352 0.359 0.346 0.387 0.394 0.380 0.317 0.323 0.312 Post-tax ROE 24% 15% 0.668 0.679 0.658 0.735 0.747 0.723 0.602 0.612 0.593 Project Pre-tax IRR - Base Capex/Opex 25.73% 20% 0.501 0.509 0.493 0.551 0.560 0.542 0.452 0.459 0.444 Rev $/kWy 878 25% 0.401 0.408 0.395 0.441 0.448 0.434 0.361 0.367 0.356

Solar < 10kWCAPEX Base case CAPEX + 10% CAPEX -10%

70

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 15% 0.481 0.492 0.471 0.529 0.541 0.518 0.434 0.443 0.424 Project Pre-tax IRR - Base Capex/Opex 18.66% 20% 0.361 0.369 0.353 0.397 0.405 0.388 0.325 0.332 0.318 Rev $/kWy 633 25% 0.289 0.295 0.283 0.317 0.324 0.311 0.260 0.266 0.255 Post-tax ROE 20% 15% 0.562 0.572 0.551 0.617 0.629 0.606 0.506 0.516 0.497 Project Pre-tax IRR - Base Capex/Opex 22.31% 20% 0.421 0.429 0.413 0.463 0.472 0.454 0.380 0.387 0.373 Rev $/kWy 738 25% 0.337 0.343 0.331 0.370 0.377 0.363 0.304 0.309 0.298 Post-tax ROE 24% 15% 0.639 0.650 0.629 0.703 0.714 0.691 0.576 0.586 0.567 Project Pre-tax IRR - Base Capex/Opex 25.73% 20% 0.480 0.487 0.472 0.527 0.536 0.518 0.432 0.439 0.425 Rev $/kWy 840 25% 0.384 0.390 0.377 0.422 0.428 0.415 0.346 0.351 0.340

CAPEX Base case CAPEX + 10% CAPEX -10%Solar 10 - 250kW

71

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 15% 0.430 0.439 0.421 0.473 0.483 0.462 0.388 0.396 0.379 Project Pre-tax IRR - Base Capex/Opex 18.66% 20% 0.323 0.330 0.316 0.354 0.362 0.347 0.291 0.297 0.284 Rev $/kWy 565 25% 0.258 0.264 0.252 0.284 0.290 0.277 0.233 0.238 0.227 Post-tax ROE 20% 15% 0.502 0.511 0.492 0.551 0.562 0.541 0.452 0.461 0.444 Project Pre-tax IRR - Base Capex/Opex 22.30% 20% 0.376 0.383 0.369 0.414 0.421 0.406 0.339 0.345 0.333 Rev $/kWy 659 25% 0.301 0.307 0.295 0.331 0.337 0.325 0.271 0.276 0.266 Post-tax ROE 24% 15% 0.571 0.581 0.562 0.628 0.638 0.617 0.515 0.523 0.506 Project Pre-tax IRR - Base Capex/Opex 25.73% 20% 0.428 0.435 0.421 0.471 0.478 0.463 0.386 0.392 0.380 Rev $/kWy 751 25% 0.343 0.348 0.337 0.377 0.383 0.370 0.309 0.314 0.304

Solar 250 - 2MWCAPEX Base case CAPEX + 10% CAPEX -10%

72

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 15% 0.353 0.361 0.345 0.388 0.397 0.379 0.318 0.325 0.311 Project Pre-tax IRR - Base Capex/Opex 17.47% 20% 0.265 0.271 0.259 0.291 0.297 0.284 0.238 0.244 0.233 Rev $/kWy 464 25% 0.212 0.217 0.207 0.233 0.238 0.227 0.191 0.195 0.186 Post-tax ROE 20% 15% 0.406 0.414 0.398 0.446 0.455 0.437 0.366 0.373 0.358 Project Pre-tax IRR - Base Capex/Opex 20.64% 20% 0.304 0.310 0.298 0.334 0.341 0.328 0.274 0.280 0.269 Rev $/kWy 533 25% 0.243 0.248 0.239 0.268 0.273 0.262 0.219 0.224 0.215 Post-tax ROE 24% 15% 0.457 0.465 0.448 0.502 0.511 0.493 0.411 0.419 0.404 Project Pre-tax IRR - Base Capex/Opex 23.57% 20% 0.342 0.348 0.336 0.376 0.383 0.370 0.309 0.314 0.303 Rev $/kWy 600 25% 0.274 0.279 0.269 0.301 0.306 0.296 0.247 0.251 0.242

Solar 2 - 5MWCAPEX Base case CAPEX + 10% CAPEX -10%

73

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 15% 0.315 0.323 0.308 0.346 0.355 0.338 0.284 0.291 0.277 Project Pre-tax IRR - Base Capex/Opex 16.47% 20% 0.236 0.242 0.231 0.260 0.266 0.254 0.213 0.218 0.208 Rev $/kWy 414 25% 0.189 0.194 0.185 0.208 0.213 0.203 0.170 0.175 0.166 Post-tax ROE 20% 15% 0.359 0.366 0.351 0.394 0.402 0.386 0.323 0.330 0.316 Project Pre-tax IRR - Base Capex/Opex 19.28% 20% 0.269 0.275 0.263 0.296 0.302 0.289 0.242 0.247 0.237 Rev $/kWy 471 25% 0.215 0.220 0.211 0.236 0.241 0.231 0.194 0.198 0.190 Post-tax ROE 24% 15% 0.400 0.408 0.392 0.440 0.448 0.431 0.360 0.367 0.354 Project Pre-tax IRR - Base Capex/Opex 21.87% 20% 0.300 0.306 0.294 0.330 0.336 0.323 0.270 0.275 0.265 Rev $/kWy 526 25% 0.240 0.245 0.235 0.264 0.269 0.259 0.216 0.220 0.212

CAPEX Base case CAPEX + 10% CAPEX -10%Solar 5 <10MW

74

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 20% 0.288 0.296 0.281 0.317 0.325 0.308 0.260 0.267 0.253 Project Pre-tax IRR - Base Capex/Opex 18.66% 27% 0.214 0.219 0.208 0.235 0.241 0.228 0.192 0.198 0.187 Rev $/kWy 505 34% 0.170 0.174 0.165 0.186 0.191 0.181 0.153 0.157 0.149 Post-tax ROE 20% 20% 0.335 0.343 0.327 0.368 0.377 0.360 0.302 0.309 0.295 Project Pre-tax IRR - Base Capex/Opex 22.30% 27% 0.248 0.254 0.243 0.273 0.279 0.267 0.224 0.229 0.219 Rev $/kWy 587 34% 0.197 0.202 0.193 0.217 0.222 0.212 0.178 0.182 0.174 Post-tax ROE 24% 20% 0.380 0.388 0.373 0.418 0.426 0.410 0.343 0.350 0.336 Project Pre-tax IRR - Base Capex/Opex 25.73% 27% 0.282 0.287 0.276 0.310 0.316 0.303 0.254 0.259 0.249 Rev $/kWy 667 34% 0.224 0.228 0.219 0.246 0.251 0.241 0.202 0.206 0.198

Wind < 10kWCAPEX Base case CAPEX + 10% CAPEX -10%

75

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 20% 0.264 0.271 0.257 0.291 0.298 0.283 0.238 0.245 0.232 Project Pre-tax IRR - Base Capex/Opex 18.66% 27% 0.196 0.201 0.191 0.215 0.221 0.209 0.176 0.181 0.172 Rev $/kWy 463 34% 0.156 0.160 0.151 0.171 0.175 0.166 0.140 0.144 0.136 Post-tax ROE 20% 20% 0.307 0.314 0.300 0.338 0.345 0.330 0.277 0.283 0.271 Project Pre-tax IRR - Base Capex/Opex 22.30% 27% 0.228 0.233 0.222 0.250 0.256 0.244 0.205 0.210 0.200 Rev $/kWy 538 34% 0.181 0.185 0.177 0.199 0.203 0.194 0.163 0.167 0.159 Post-tax ROE 24% 20% 0.349 0.356 0.342 0.383 0.391 0.376 0.314 0.321 0.308 Project Pre-tax IRR - Base Capex/Opex 25.73% 27% 0.258 0.264 0.253 0.284 0.290 0.278 0.233 0.237 0.228 Rev $/kWy 611 34% 0.205 0.209 0.201 0.225 0.230 0.221 0.185 0.189 0.181

Wind 10 - 250kWCAPEX Base case CAPEX + 10% CAPEX -10%

76

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 20% 0.186 0.191 0.181 0.205 0.210 0.199 0.168 0.172 0.163 Project Pre-tax IRR - Base Capex/Opex 18.66% 27% 0.138 0.142 0.134 0.152 0.156 0.148 0.124 0.128 0.121 Rev $/kWy 326 34% 0.110 0.112 0.107 0.120 0.124 0.117 0.099 0.101 0.096 Post-tax ROE 20% 20% 0.216 0.221 0.211 0.238 0.243 0.232 0.195 0.199 0.191 Project Pre-tax IRR - Base Capex/Opex 22.30% 27% 0.160 0.164 0.157 0.176 0.180 0.172 0.144 0.148 0.141 Rev $/kWy 379 34% 0.127 0.130 0.124 0.140 0.143 0.137 0.115 0.117 0.112 Post-tax ROE 24% 20% 0.246 0.251 0.241 0.270 0.275 0.265 0.221 0.226 0.217 Project Pre-tax IRR - Base Capex/Opex 25.73% 27% 0.182 0.186 0.178 0.200 0.204 0.196 0.164 0.167 0.161 Rev $/kWy 430 34% 0.145 0.147 0.142 0.159 0.162 0.156 0.130 0.133 0.128

CAPEX -10%Wind 250 - 2MW

CAPEX Base case CAPEX + 10%

77

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 20% 0.162 0.167 0.158 0.178 0.183 0.173 0.146 0.150 0.142 Project Pre-tax IRR - Base Capex/Opex 17.47% 27% 0.120 0.124 0.117 0.132 0.136 0.128 0.108 0.111 0.105 Rev $/kWy 284 34% 0.095 0.098 0.093 0.105 0.108 0.102 0.086 0.088 0.084 Post-tax ROE 20% 20% 0.186 0.191 0.181 0.204 0.209 0.199 0.168 0.172 0.164 Project Pre-tax IRR - Base Capex/Opex 20.64% 27% 0.138 0.141 0.134 0.151 0.155 0.148 0.124 0.127 0.121 Rev $/kWy 326 34% 0.109 0.112 0.107 0.120 0.123 0.117 0.099 0.101 0.096 Post-tax ROE 24% 20% 0.209 0.213 0.204 0.229 0.234 0.224 0.188 0.192 0.184 Project Pre-tax IRR - Base Capex/Opex 23.57% 27% 0.155 0.158 0.151 0.170 0.174 0.166 0.139 0.142 0.136 Rev $/kWy 366 34% 0.123 0.125 0.120 0.135 0.138 0.132 0.111 0.113 0.108

Wind 2 - 5MWCAPEX Base case CAPEX + 10% CAPEX -10%

78

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Post-tax ROE 16% 20% 0.150 0.154 0.145 0.164 0.169 0.160 0.135 0.139 0.131 Project Pre-tax IRR - Base Capex/Opex 16.47% 27% 0.111 0.114 0.108 0.122 0.125 0.118 0.100 0.103 0.097 Rev $/kWy 262 34% 0.088 0.091 0.085 0.097 0.099 0.094 0.079 0.082 0.077 Post-tax ROE 20% 20% 0.169 0.174 0.165 0.186 0.191 0.181 0.153 0.157 0.149 Project Pre-tax IRR - Base Capex/Opex 19.27% 27% 0.126 0.129 0.122 0.138 0.142 0.134 0.113 0.116 0.110 Rev $/kWy 297 34% 0.100 0.102 0.097 0.110 0.112 0.107 0.090 0.092 0.087 Post-tax ROE 24% 20% 0.189 0.193 0.184 0.207 0.212 0.202 0.170 0.174 0.166 Project Pre-tax IRR - Base Capex/Opex 21.87% 27% 0.140 0.143 0.136 0.153 0.157 0.150 0.126 0.129 0.123 Rev $/kWy 330 34% 0.111 0.113 0.108 0.122 0.125 0.119 0.100 0.102 0.098

Wind 5 <10MWCAPEX Base case CAPEX + 10% CAPEX -10%

79

REFITs : IRR driven Revenue Requirement Calculation - Equity Cash Flow ROE (post-tax) and Project Cash Flow IRR (pre-tax)

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 75% 0.178 0.193 0.163 0.196 0.212 0.179 0.160 0.173 0.147 Post-tax ROE -Base Capex/Opex 9.46% 85% 0.157 0.170 0.144 0.173 0.187 0.158 0.141 0.153 0.129 Rev $/kWy 1,168 95% 0.140 0.152 0.129 0.154 0.167 0.141 0.126 0.137 0.116 Project Pre-tax IRR 16% 75% 0.208 0.223 0.193 0.229 0.245 0.212 0.187 0.201 0.174 Post-tax ROE -Base Capex/Opex 13.90% 85% 0.184 0.197 0.170 0.202 0.216 0.187 0.165 0.177 0.153 Rev $/kWy 1,367 95% 0.164 0.176 0.153 0.181 0.193 0.168 0.148 0.158 0.137 Project Pre-tax IRR 20% 75% 0.242 0.256 0.227 0.266 0.282 0.250 0.218 0.231 0.204 Post-tax ROE -Base Capex/Opex 18.69% 85% 0.213 0.226 0.200 0.235 0.249 0.220 0.192 0.204 0.180 Rev $/kWy 1,588 95% 0.191 0.202 0.179 0.210 0.223 0.197 0.172 0.182 0.161

Bio-Mass 0.25 - 0.5MWCAPEX Base case CAPEX + 10% CAPEX -10%

80

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 75% 0.123 0.134 0.113 0.136 0.147 0.124 0.111 0.120 0.102 Post-tax ROE -Base Capex/Opex 9.95% 85% 0.109 0.118 0.100 0.120 0.130 0.110 0.098 0.106 0.090 Rev $/kWy 810 95% 0.097 0.105 0.089 0.107 0.116 0.098 0.088 0.095 0.080 Project Pre-tax IRR 16% 75% 0.144 0.154 0.134 0.159 0.170 0.147 0.130 0.139 0.121 Post-tax ROE -Base Capex/Opex 14.98% 85% 0.127 0.136 0.118 0.140 0.150 0.130 0.114 0.123 0.106 Rev $/kWy 947 95% 0.114 0.122 0.106 0.125 0.134 0.116 0.102 0.110 0.095 Project Pre-tax IRR 20% 75% 0.167 0.178 0.157 0.184 0.195 0.173 0.151 0.160 0.142 Post-tax ROE -Base Capex/Opex 20.52% 85% 0.148 0.157 0.139 0.162 0.172 0.153 0.133 0.141 0.125 Rev $/kWy 1,100 95% 0.132 0.140 0.124 0.145 0.154 0.136 0.119 0.126 0.112

Bio-Mass 0.5 - 5MWCAPEX Base case CAPEX + 10% CAPEX -10%

81

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 75% 0.093 0.100 0.085 0.102 0.110 0.093 0.083 0.090 0.076 Post-tax ROE -Base Capex/Opex 10.45% 85% 0.082 0.089 0.075 0.090 0.097 0.082 0.074 0.080 0.067 Rev $/kWy 609 95% 0.073 0.079 0.067 0.080 0.087 0.074 0.066 0.071 0.060 Project Pre-tax IRR 16% 75% 0.108 0.116 0.100 0.119 0.127 0.110 0.097 0.104 0.090 Post-tax ROE -Base Capex/Opex 16.07% 85% 0.095 0.102 0.089 0.105 0.112 0.097 0.086 0.092 0.080 Rev $/kWy 710 95% 0.085 0.091 0.079 0.094 0.101 0.087 0.077 0.082 0.071 Project Pre-tax IRR 20% 75% 0.125 0.133 0.118 0.138 0.146 0.129 0.113 0.120 0.106 Post-tax ROE -Base Capex/Opex 22.31% 85% 0.111 0.117 0.104 0.122 0.129 0.114 0.100 0.106 0.093 Rev $/kWy 823 95% 0.099 0.105 0.093 0.109 0.116 0.102 0.089 0.095 0.084

Bio-Mass 5 <10MWCAPEX Base case CAPEX + 10% CAPEX -10%

82

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 15% 0.361 0.372 0.350 0.398 0.410 0.385 0.325 0.335 0.315 Post-tax ROE -Base Capex/Opex 9.25% 20% 0.271 0.279 0.263 0.298 0.307 0.289 0.244 0.251 0.237 Rev $/kWy 475 25% 0.217 0.223 0.210 0.239 0.246 0.231 0.195 0.201 0.189 Project Pre-tax IRR 16% 15% 0.444 0.455 0.434 0.489 0.501 0.477 0.400 0.410 0.390 Post-tax ROE -Base Capex/Opex 13.23% 20% 0.333 0.342 0.325 0.367 0.376 0.358 0.300 0.307 0.293 Rev $/kWy 584 25% 0.267 0.273 0.260 0.293 0.301 0.286 0.240 0.246 0.234 Project Pre-tax IRR 20% 15% 0.534 0.545 0.523 0.587 0.599 0.575 0.480 0.490 0.471 Post-tax ROE -Base Capex/Opex 17.44% 20% 0.400 0.409 0.392 0.440 0.449 0.431 0.360 0.368 0.353 Rev $/kWy 701 25% 0.320 0.327 0.314 0.352 0.359 0.345 0.288 0.294 0.282

Solar < 10kWCAPEX Base case CAPEX + 10% CAPEX -10%

83

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 15% 0.346 0.356 0.335 0.380 0.392 0.369 0.311 0.321 0.302 Post-tax ROE -Base Capex/Opex 9.25% 20% 0.259 0.267 0.251 0.285 0.294 0.276 0.233 0.241 0.226 Rev $/kWy 454 25% 0.207 0.214 0.201 0.228 0.235 0.221 0.187 0.192 0.181 Project Pre-tax IRR 16% 15% 0.425 0.436 0.415 0.468 0.479 0.456 0.383 0.392 0.373 Post-tax ROE -Base Capex/Opex 13.22% 20% 0.319 0.327 0.311 0.351 0.359 0.342 0.287 0.294 0.280 Rev $/kWy 559 25% 0.255 0.261 0.249 0.281 0.288 0.274 0.230 0.235 0.224 Project Pre-tax IRR 20% 15% 0.511 0.521 0.500 0.562 0.573 0.550 0.460 0.469 0.450 Post-tax ROE -Base Capex/Opex 17.44% 20% 0.383 0.391 0.375 0.421 0.430 0.413 0.345 0.352 0.338 Rev $/kWy 671 25% 0.306 0.313 0.300 0.337 0.344 0.330 0.276 0.281 0.270

Solar 10 - 250kWCAPEX Base case CAPEX + 10% CAPEX -10%

84

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 15% 0.309 0.318 0.299 0.340 0.350 0.329 0.278 0.287 0.270 Post-tax ROE -Base Capex/Opex 9.25% 20% 0.232 0.239 0.225 0.255 0.263 0.247 0.209 0.215 0.202 Rev $/kWy 406 25% 0.185 0.191 0.180 0.204 0.210 0.198 0.167 0.172 0.162 Project Pre-tax IRR 16% 15% 0.380 0.389 0.371 0.418 0.428 0.408 0.342 0.350 0.334 Post-tax ROE -Base Capex/Opex 13.23% 20% 0.285 0.292 0.278 0.313 0.321 0.306 0.256 0.263 0.250 Rev $/kWy 499 25% 0.228 0.234 0.222 0.251 0.257 0.245 0.205 0.210 0.200 Project Pre-tax IRR 20% 15% 0.456 0.466 0.447 0.502 0.512 0.491 0.411 0.419 0.402 Post-tax ROE -Base Capex/Opex 17.45% 20% 0.342 0.349 0.335 0.376 0.384 0.369 0.308 0.314 0.302 Rev $/kWy 599 25% 0.274 0.279 0.268 0.301 0.307 0.295 0.246 0.251 0.241

Solar 250 - 2MWCAPEX Base case CAPEX + 10% CAPEX -10%

85

CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 15% 0.268 0.276 0.259 0.294 0.303 0.285 0.241 0.248 0.234 Post-tax ROE -Base Capex/Opex 9.71% 20% 0.201 0.207 0.195 0.221 0.227 0.214 0.181 0.186 0.175 Rev $/kWy 352 25% 0.161 0.165 0.156 0.177 0.182 0.171 0.145 0.149 0.140 Project Pre-tax IRR 16% 15% 0.329 0.337 0.321 0.362 0.371 0.353 0.296 0.303 0.289 Post-tax ROE -Base Capex/Opex 14.24% 20% 0.247 0.253 0.241 0.271 0.278 0.265 0.222 0.228 0.217 Rev $/kWy 432 25% 0.197 0.202 0.193 0.217 0.222 0.212 0.178 0.182 0.173 Project Pre-tax IRR 20% 15% 0.395 0.403 0.387 0.434 0.443 0.426 0.356 0.363 0.348 Post-tax ROE -Base Capex/Opex 19.17% 20% 0.296 0.302 0.290 0.326 0.332 0.319 0.267 0.272 0.261 Rev $/kWy 519 25% 0.237 0.242 0.232 0.261 0.266 0.255 0.213 0.218 0.209

Solar 2 - 5MWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 15% 0.251 0.258 0.243 0.276 0.284 0.267 0.226 0.233 0.219 Post-tax ROE -Base Capex/Opex 10.23% 20% 0.188 0.194 0.182 0.207 0.213 0.201 0.169 0.174 0.164 Rev $/kWy 330 25% 0.150 0.155 0.146 0.166 0.171 0.160 0.135 0.140 0.131 Project Pre-tax IRR 16% 15% 0.308 0.316 0.301 0.339 0.347 0.331 0.277 0.284 0.271 Post-tax ROE -Base Capex/Opex 15.36% 20% 0.231 0.237 0.225 0.254 0.261 0.248 0.208 0.213 0.203 Rev $/kWy 405 25% 0.185 0.190 0.180 0.203 0.208 0.198 0.166 0.171 0.162 Project Pre-tax IRR 20% 15% 0.370 0.378 0.362 0.407 0.415 0.399 0.333 0.340 0.326 Post-tax ROE -Base Capex/Opex 21.09% 20% 0.278 0.283 0.272 0.305 0.312 0.299 0.250 0.255 0.245 Rev $/kWy 486 25% 0.222 0.227 0.217 0.244 0.249 0.239 0.200 0.204 0.196

Solar 5 <10MWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 20% 0.209 0.217 0.202 0.230 0.239 0.222 0.188 0.195 0.181 Post-tax ROE -Base Capex/Opex 9.25% 27% 0.155 0.161 0.149 0.171 0.177 0.164 0.140 0.145 0.134 Rev $/kWy 367 34% 0.123 0.128 0.119 0.135 0.140 0.130 0.111 0.115 0.107 Project Pre-tax IRR 16% 20% 0.256 0.263 0.248 0.281 0.290 0.273 0.230 0.237 0.223 Post-tax ROE -Base Capex/Opex 13.23% 27% 0.189 0.195 0.184 0.208 0.214 0.202 0.170 0.176 0.165 Rev $/kWy 448 34% 0.150 0.155 0.146 0.165 0.170 0.160 0.135 0.139 0.131 Project Pre-tax IRR 20% 20% 0.305 0.313 0.298 0.336 0.344 0.327 0.275 0.282 0.268 Post-tax ROE -Base Capex/Opex 17.45% 27% 0.226 0.232 0.221 0.249 0.255 0.243 0.204 0.209 0.199 Rev $/kWy 535 34% 0.180 0.184 0.175 0.198 0.203 0.193 0.162 0.166 0.158

Wind < 10kWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 20% 0.192 0.199 0.185 0.211 0.219 0.203 0.173 0.179 0.166 Post-tax ROE -Base Capex/Opex 9.25% 27% 0.142 0.147 0.137 0.156 0.162 0.151 0.128 0.133 0.123 Rev $/kWy 336 34% 0.113 0.117 0.109 0.124 0.129 0.120 0.102 0.105 0.098 Project Pre-tax IRR 16% 20% 0.234 0.241 0.227 0.258 0.265 0.250 0.211 0.217 0.205 Post-tax ROE -Base Capex/Opex 13.22% 27% 0.174 0.179 0.168 0.191 0.197 0.185 0.156 0.161 0.152 Rev $/kWy 411 34% 0.138 0.142 0.134 0.152 0.156 0.147 0.124 0.128 0.120 Project Pre-tax IRR 20% 20% 0.280 0.287 0.273 0.308 0.316 0.300 0.252 0.258 0.246 Post-tax ROE -Base Capex/Opex 17.44% 27% 0.207 0.213 0.202 0.228 0.234 0.222 0.187 0.191 0.182 Rev $/kWy 490 34% 0.165 0.169 0.161 0.181 0.186 0.177 0.148 0.152 0.145

Wind 10 - 250kWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 20% 0.135 0.140 0.130 0.149 0.154 0.143 0.122 0.126 0.117 Post-tax ROE -Base Capex/Opex 9.25% 27% 0.100 0.104 0.096 0.110 0.114 0.106 0.090 0.093 0.087 Rev $/kWy 237 34% 0.080 0.082 0.077 0.087 0.091 0.084 0.072 0.074 0.069 Project Pre-tax IRR 16% 20% 0.165 0.170 0.160 0.182 0.187 0.176 0.149 0.153 0.144 Post-tax ROE -Base Capex/Opex 13.23% 27% 0.122 0.126 0.119 0.135 0.139 0.130 0.110 0.113 0.107 Rev $/kWy 289 34% 0.097 0.100 0.094 0.107 0.110 0.104 0.087 0.090 0.085 Project Pre-tax IRR 20% 20% 0.197 0.202 0.192 0.217 0.222 0.212 0.178 0.182 0.173 Post-tax ROE -Base Capex/Opex 17.45% 27% 0.146 0.150 0.142 0.161 0.165 0.157 0.131 0.135 0.128 Rev $/kWy 346 34% 0.116 0.119 0.113 0.128 0.131 0.124 0.104 0.107 0.102

Wind 250 - 2MWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 20% 0.124 0.129 0.120 0.137 0.142 0.132 0.112 0.116 0.108 Post-tax ROE -Base Capex/Opex 9.71% 27% 0.092 0.095 0.089 0.101 0.105 0.098 0.083 0.086 0.080 Rev $/kWy 218 34% 0.073 0.076 0.070 0.080 0.083 0.077 0.066 0.068 0.063 Project Pre-tax IRR 16% 20% 0.152 0.156 0.147 0.167 0.172 0.162 0.137 0.141 0.132 Post-tax ROE -Base Capex/Opex 14.24% 27% 0.112 0.116 0.109 0.124 0.127 0.120 0.101 0.104 0.098 Rev $/kWy 266 34% 0.089 0.092 0.087 0.098 0.101 0.095 0.080 0.083 0.078 Project Pre-tax IRR 20% 20% 0.181 0.186 0.177 0.199 0.204 0.194 0.163 0.167 0.159 Post-tax ROE -Base Capex/Opex 19.17% 27% 0.134 0.138 0.131 0.148 0.151 0.144 0.121 0.124 0.118 Rev $/kWy 317 34% 0.107 0.109 0.104 0.117 0.120 0.114 0.096 0.098 0.094

Wind 2 - 5MWCAPEX Base case CAPEX + 10% CAPEX -10%

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CF

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Opex Base case

($/kWh)

Opex 20%

($/kWh)

Opex -20%

($/kWh)

Project Pre-tax IRR 12% 20% 0.120 0.124 0.115 0.132 0.137 0.127 0.108 0.112 0.104 Post-tax ROE -Base Capex/Opex 10.23% 27% 0.089 0.092 0.086 0.098 0.101 0.094 0.080 0.083 0.077 Rev $/kWy 210 34% 0.071 0.073 0.068 0.078 0.080 0.075 0.063 0.066 0.061 Project Pre-tax IRR 16% 20% 0.146 0.151 0.142 0.161 0.166 0.156 0.132 0.136 0.128 Post-tax ROE -Base Capex/Opex 15.37% 27% 0.108 0.112 0.105 0.119 0.123 0.116 0.098 0.100 0.095 Rev $/kWy 256 34% 0.086 0.089 0.083 0.095 0.097 0.092 0.077 0.080 0.075 Project Pre-tax IRR 20% 20% 0.175 0.179 0.170 0.192 0.197 0.187 0.157 0.161 0.153 Post-tax ROE -Base Capex/Opex 21.09% 27% 0.129 0.133 0.126 0.142 0.146 0.139 0.116 0.119 0.114 Rev $/kWy 306 34% 0.103 0.105 0.100 0.113 0.116 0.110 0.093 0.095 0.090

Wind 5 <10MWCAPEX Base case CAPEX + 10% CAPEX -10%

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Section 7 PPA Guidelines

The PPA Guidelines listed in this Section are principles to serve as roadmap in the negotiations of PPAs entered into between NamPower and the IPP(s) under the recommendations contained herein. These guidelines do not advocate a standard PPA, as standard “fill in the blanks” PPAs do not allow enough flexibility. Instead, these guidelines seek to provide uniformity in principles, and in particular, compliance with the Regulations provided in Section 1, along with flexibility when negotiated between an IPP, as Seller, and NamPower as the Offtaker, and monitored for compliance by ECB, as Regulator.

Commercial Basis: Projects seeking to sign a REFIT based PPA subject to the Regulations proposed herein must be technically, legally, environmentally viable and meet the financing criteria of their creditors/investors. The Offtaker, NamPower, retains the right to deny signing the requisite PPA and deny access to the Grid (see Section 8).

Legal and Regulatory Compliance: All contracted PPAs should comply with all relevant laws, regulations, codes and policies of the Government of Namibia.

Payment: All PPAs should be in the form of a “take-or pay contract.”

Period: The term of the PPA for a REFIT based procurement should be for 20 years and it may provide for extensions by mutual agreement, subject to proper maintenance and refurbishment of assets in the interim, as agreed by the parties. As a general rule, the term of a PPA must, at a minimum, match the maturity of the loans financing the project, which in turn should be less than the average anticipated life of the plant.

Currency: REFITs should be payable in US$ (this can be adjusted to another hard currency by the mutual agreement of the parties to the PPA) so that the IPPs do not take any currency exposure, provided that projects financed in local currency for any portion of the financing required (long term plus equity) shall be payable in local currency for that proportion of the due payment. Notwithstanding this provision, the actual transaction for the associated invoice can be made in local currency at the prevailing exchange rate71

on the date of such invoice, provided that the parties reach mutually satisfactory arrangements to mitigate convertibility and transferability risks associated with such payments in servicing debt and repatriating capital and profits

Capacity Charges vs. Energy Charges: Projects seeking to sign a REFIT based PPA should have an Energy Charge only.

Firm or Non-firm Energy: Notwithstanding the Energy-Charge-only principle, the parties to the PPA may, by mutual agreement, choose to convert a certain portion of the projected total annual Energy Charge to a Firm Energy portion payable at a 10%

71 Means the US$/NAD offered exchange rate prevailing at the close of business by the Bank of Namibia on the date of the invoice.

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premium (same 10% applicable to all projects willing to commit and for the amount they are willing to declare firm), provided that a mutually agreed penalty exceeding this 10% (amount to exceed 10% is left to the discretion of the parties in each PPA) is imposed, if the firm commitment is not honored by the IPP. The certainty with which power is provided should be clearly defined, but it does not have to be uniform across all projects.

Indexation: Indexation shall be applied to old (those post-project completion) and new projects (those pre-PPA signing) in a manner that (i) REFITs stated in Power Purchase Agreements for old projects will be adjusted on the basis of the US$ Producer Price Index (PPI) starting from the year of the PPA at financial closure, and (ii) REFIT tables (applicable to new project), on the basis of US$ PPI plus differential inflation (as compared to the PPI) consisting of a basket of fuel, cement, steel and labor (unless other cost factors are added in the interim before fixing the methodology). This shall be made public every year by the ECB, so that all IPPs can be assured of a level of price predictability.

Operating Regime: Actual dispatch should be done by NamPower in its capacity as system operator of the grid. Scheduled Maintenance planning should be coordinated and approved with NamPower within the operating parameters of the plant’s technology. Ancillary services should be included in the PPA, as mutually agreed and at separate compensation.

System Losses and Imbalances: Losses attributable to the IPP(s) need to be allocated as such. The IPP should be bound to follow the directions of the system operator, except where it is necessary to take measures to prevent imminent damage to its own or any other equipment, and should maintain system parameters within acceptable/reasonable limits as per the Grid Code, except where it is necessary to take measures to prevent imminent damage to its own or any other equipment.

Point of Sale/ Point of Delivery: The point of sale/delivery (and therefore transfer of ownership and risk) of the energy, for REFIT based projects that are within [specified distance] of the grid, should be at the generating plant site. This follows the principle that only projects that are within [specified distance] of the grid shall be eligible for REFITs and without any penalty or reward for the distance from such grid. Nevertheless, NamPower, at its sole discretion, shall retain the right to accept or reject projects beyond [specified distance] (a) for off grid development, or (b) for a negotiated discount on the applicable REFIT/FIT price, based on the extra distance [specified distance], or (c) at the developer’s offer to assume the costs and build the line beyond [specified distance]. This is so as the proposed REFITs are calculated on cost plus return basis to the generation project, without consideration to the distance and cost to the grid connection. This avoids generalizing for all projects and having the closer ones have a windfall while distant ones forego a price increment. This provision should be tempered by case specific considerations, at the discretion of NamPower, as Offtaker, when network development on the occasion of one particular IPP would give access to other potential IPPs, in which case any grid extension costs beyond the [specified distance] perimeter should be apportioned by NamPower, as it reasonably sees fit and practicable, to simultaneous

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beneficiaries (i.e. two consecutive beneficiaries that are beyond the [specified distance] limit but are within [specified distance] of each other should share the costs in a reasonably proportioned way.)

Deemed Energy Output Payments due to Transmission Line Construction Delays: This will be payable under the terms of the take-or-pay arrangements of a signed PPA by NamPower to the IPP, for projects within [specified distance] distance from the grid, if NamPower does not make the transmission line connection available within the time frame mutually agreed by NamPower and the IPP in the Transmission Connection Agreement. For projects beyond [specified distance], within NamPower’s discretion to accept or reject such projects, the payable Deemed Energy Output should be as agreed by the Parties.

Responsibility for Connection/ Interconnectors: Responsibility for connection to the point of delivery must reside with the IPP and associated losses with delivery to such point allocated to the IPP’s account.

Carbon Credits and Other Similar Benefits: The REFIT levels are based on cost plus return estimates not taking into account any windfall benefits to the developer accruing from carbon credits. As such, these benefits should be duly released and assigned to the government. However, the government through NamPower, at its sole discretion, may choose to split the proceeds at some pre-negotiated proportion, if it deems such partitioning would incentivize a particularly well positioned IPP with experience in this carbon credit market to collect such credits. This is on the basis that the REFITs are calculated at cost plus return before any carbon credit benefits.

Liabilities/Damages/ Losses/ Compensation Events: The PPA should make provisions for adequate protection of, and compensation to NamPower in the event of default by the IPP. Similar provisions should be applicable to the IPP for events of default caused by NamPower along with the guarantees against expropriation.

Triggers for Exceptional Circumstances: Certain exceptional circumstances, and associated pre-agreed principles for remedies, should be recognized in the PPA, examples of which include:

o Change in regulatory framework o Change in law and in the tax regimeo Project fails before it comes on lineo Project becomes uneconomico Force Majeureo Failure to meet a financial obligation vis-a-vis banks and other investors.

Warranties: Sufficient warranties to cover NamPower’s exposure in the event of non-performance by the IPP, including Seller abandonment, must be put in place. Take-or-pay arrangements should cover the IPP for non-performance by NamPower.

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Applicable Law: While the standard would be to have Law of Namibia with Namibian Courts as seat for arbitration, flexibility can be exercised given the preferences of the parties and financing banks involved, particularly taking into account security and trustee arrangements that may be required by international banks to make the associated PPA bankable, with offshore escrow accounts subject to foreign law jurisdiction.

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Section 8 Application and Project Screening Protocol

Along with listing the REFIT tariffs and defining the applicable Regulations and PPA Guidelines which are intended to guarantee transparency, predictability and risk allocation parameters, a successful REFIT Program also requires an application and project screening protocol, as a one-stop shop approach, to facilitate decision-making in issuing proper generation licenses to IPPs to develop RE power projects under this Program.

This approach proposes the formation of an IPP Committee72 comprising representatives of the Ministry of Mines and Energy (MME), NamPower, ECB, and other entities as deemed necessary, and chaired by the [designated authority], to evaluate the applicants’ expressions of interest and pre-feasibility requirements of an RE project and accordingly to issue a proper generation licenses. 8.1 The IPP Committee

8.1.1 Private investors who wish to become power producers shall send an Expression of Interest (EOI) to […], attention of the [designated authority] chairing the IPP Committee.

8.1.2 The IPP Committee shall review the EOI and communicate its determination on the proposed project within [forty] business days from the date of receipt of the EOI.

8.1.3 The IPP Committee’s determination shall be limited to issuing a non-objection or objection to NamPower as offtaker to enter into PPA negotiations and to ECB to issue the proper license.

8.1.4 Upon the lapsing of the aforementioned [forty] business days, the absence of any determination from the IPP Committee shall be deemed as a non-objection, by the same IPP Committee, to the proposed project, as structured and conceived.

8.1.5 The IPP Committee’s deliberations to issuing an objection shall be confined to determining that the proposed project: (a) has a priori evidence for it not to be deemed a Viable Project73; and/or (b) is of a size and distance from the Grid whose connection costs and associated transmission losses make it unfeasible to burden the consumers with such connection costs.

72 Although ECB does have a licensing procedure to be followed, the purpose of the IPP Committee is not to replace such procedure but to form a one-stop forum by key stakeholders, so individual projects can be pre-screened on a pre-feasibility basis. ECB and NamPower, respectively, retain their procedures for ECB to independently issue or not licenses and for NamPower to enter or not into PPAs, once the non-objection of the IPP Committee has been obtained. 73 A Viable Project means a project involving the construction of a power plant which in its conception, design, planning, and execution meets the standards of best practice in each of the disciplines involved that will render such project feasible with respect to technical, commercial, financial, economic, environmental, regulatory, legal, and other relevant criteria.

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8.1.6 The declaration of an objection from the IPP Committee shall prevent: (a) NamPower as the offtaker from entering into a PPA with the applicant on the proposed project in the manner it is structured and conceived, unless restructured and enhanced, in which case the project by the same developer, conceived under a more viable structure, may be presented to the IPP Committee for a second and final consideration; and (b) ECB from issuing the proper license.

8.1.7 The declaration of a non-objection from the IPP Committee or the lapsing of the aforementioned [forty] business days with no declaration shall not (a) be deemed to be an endorsement that the proposed project is a Viable Project; or (b) obligate NamPower as the offtaker, a commercial entity that reserves its own right to make its own independent assessments, to enter into a PPA or not; or (c) obligate ECB, an independent overseeing authority, to make its own independent determination, to issue the proper license.

8.1.8 In the interim of the aforementioned [forty] business days NamPower as offtaker, at its sole discretion, shall be free to initiate, but not complete, PPA negotiations, and ECB, at its sole discretion, shall be free to initiate, but not complete, due process for issuing the proper license.

8.2 The Expression of Interest (EOI)

8.2.1 The EOI is the first communication of the applicant’s intention to develop and invest in a project under the proposed Regulations contained herein.

8.2.2 It is expected that an applicant who sends an EOI has (a) undertaken a pre-feasibility study, and (b) can provide all the relevant information, further described below in this Section, to the IPP Committee to facilitate decision making.

8.2.3 The information provided in the EOI should be of sufficient breadth and depth to demonstrate the applicant’s commitment and ability to proceed (upon receipt of a non-objection by the IPP Committee) with further development of the project, to establish the proposed project as a potentially bankable project, all subject to a full feasibility study being completed subsequently, an associated environmental impact assessment (EIA) being accepted by all the competent authorities, and a proper PPA being duly signed under the tariff structures proposed herein.

8.2.4 The EOI should as a minimum contain the information sought hereunder:

1) Particulars of the Applicant: Listing of key elements of the identity and commercial structure of the applicant, to the extent applicable:

Name of Applicant (Business/Entity/Group) Type of Entity (sole proprietorship, private limited partnership, public limited

partnership, corporation, joint venture, other) Date of Incorporation Head Office Address Telephone # Fax #

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E-Mail Website Main Business Activities Authorized Share Capital where applicable Business/Entity ownership and shareholding structure, identifying parent and subsidiary

companies, where applicable Implementation Agreement or Concession Agreement, if any, for the project Shareholder’s Agreement, if applicable Articles and By-Laws of the Single Purpose Vehicle, if created for the project Business/Entity Registration Certificate Income Tax Registration (PIN) Certificate VAT Registration Certificate

2) Project Site Location: Description of the project site location giving sufficient details to enable the IPP Committee to easily identify the site, including but not limited to:

Site name GPS and/or geographical co-ordinates Nearest urban center Location/Division/Region

3) Site and Land Ownership and Control: Indication of the site ownership and, if applicant is not the owner of the land, indication of how the project developers intend to acquire and control the site either through long term lease, buy-out, or other arrangements.

4) Technology: Description of the technology to be employed: Biomass Solar PV Wind

5) Pre-Feasibility Study: which means a preliminary study or collection of preliminary studies associated with the planning of a contemplated plant and the related preliminary or advanced stage data to assess,

the quality of the energy resource base to be used the technology to be applied the installed capacity contemplated for the plant its associated capital and operating costs the capacity factor at which the plant is expected to operate the availability and expected annual electricity sales the associated market the plant will serve the proposed financial plan including amounts of debt, equity (and grants, if any),

provided that the debt portion may not be more than 75% of total financing required74,

74 Total Financing Required means the total capital needed in the form of debt or equity (or grants) to meet the

capital costs required to build and deliver a Plant to agreed and ordinarily accepted standards, including but not limited to Base Costs, Physical Contingencies, Price Contingencies, Working Capital, plus Interest During Construction.

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the possible sources of finance the loan security arrangements contemplated, including loan guarantees, trustee

arrangements, escrow accounts, assignments of rights/proceeds from project revenues associated with project agreements such as the PPA, security interests in project support guaranties, first mortgages/pledges on project assets, pledges on sponsor ownership rights over project, etc.

the expected financial viability at the applicable REFIT, along with financial projections on the project, if any

the environmental impact the economic impact basic information on financial advisors, if any, to assist the applicantwhich together establish a sufficient basis for practitioners knowledgeable in such matters to determine that a Viable Project is very likely to be conceived, designed, planned, and executed if and when certain key parameters in the areas of technical, commercial, financial, economic, environmental, regulatory, legal, and other relevant disciplines are further investigated and properly structured.

6) Project Sponsors and Developers means a brief description of the following: Background and experience with similar projects, plants, and technologies Audited financial statements of the developer, partners, and key sponsors Governance and accountability arrangements

7) Technical Advisors/ Experts: means an outline of the technical advisors indicating their capability and experience in similar technology development projects.

8) Project Development and Implementation Plan: means an outline of project development and implementation plan, including time schedules for major tasks and milestones, type of contract for implementation, including type of Engineering, Procurement and Construction (EPC) Contract if such is contemplated, plus contractor’s experience, procurement and tendering arrangements, and project completion support and cost overrun coverage guarantees contemplated, if any.

9) Environmental: means a preliminary EIA and remedial action plan contemplated.

10) Insurance means a description of insurance arrangements contemplated during construction and during operation, if any.

8.3 Foreign Investor Provision

8.3.1 Foreign investors qualify to invest under the provisions of the proposed Regulations and PPA Guidelines subject to compliance with other relevant laws governing foreign investments.

8.4 Full Feasibility Study Requirement

8.4.1 Upon receipt of a non-objection by the IPP Committee, the applicant who wishes to complete negotiations of a PPA with NamPower as offtaker to be duly signed under the

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provisions proposed herein, must proceed to completing (a) a full feasibility study75 acceptable to creditors and investors who collectively can demonstrate they will provide the debt and equity financing necessary to provide the total financing required to complete the project in question, and (b) an associated EIA, acceptable to all the competent authorities, as well as creditors and investors.

8.4.2 The applicant, as the potential Seller and thus potential party to the PPA to be signed, shall submit the full feasibility study and the associated EIA to NamPower for its determination, in its reasonable judgment and as a commercial entity about to enter as the other party to the same PPA, whether the proposed project is a Viable Project that has been established as bankable, by the identification of sufficient sources that provide the total financing required and in a debt:equity ratio where the equity as a minimum is such that the ratio is 75:25.

8.4.3 NamPower may not unreasonably and without evidence to the contrary withhold determination of a Viable Project, when a project has obtained the proper license from ECB and has been proven bankable by the presence of creditors and investors ready to collectively provide the total financing required.

8.4.4 The applicant shall seek all other necessary and customary approvals for its feasibility study and EIA from the competent authorities, including MME, ECB, and others, as a condition precedent for the PPA.

8.5 Submissions and Deadlines

8.5.1 EOIs and enquiries on REFITs should be addressed to [designated authority].

8.5.2 EOIs and enquiries may be submitted through regular mail, electronic mail, or delivered by hand.

8.5.3 The implementation of the REFITs is a continuous process. Investors should however note that applications will be processed and approved on a first come first served basis and that applications that are received after the attainment of the capacity targets set under Regulation 10 shall not be considered.

75 This does not replace the licensing procedure and requirements but it is a parallel and necessary undertaking that is needed to make the project bankable to the investor community.

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Annex 1 Existing Transmission and Distribution Networks

Source: NamPower Annual Report 2011

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Annex 2 Global Horizontal Irradiance (GHI) Namibia

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Annex 3 Direct Normal Irradiance (DNI) Namibia

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Annex 4 Power Density 80m Namibia

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Annex 5 Wind Speed 80m Namibia

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