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EUEI-PDF Kenya 2013 Project Renewable Energy Regulatory Capacity Development

Assessment of a net metering programme in Kenya

Volume 1: Main report

March 2014

This study has been undertaken for the Government of the Republic of Kenya to establish a framework for net metering that will help to increase renewable electricity generation in Kenya. The financial support of the European Union is gratefully acknowledged.

Supported by the European Union

Under the Africa-EU Renewable Energy Cooperation Programme (RECP)

through Project Manager: Michael Franz European Union Energy Initiative Partnership Dialogue Facility (EUEI PDF) c/o Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) P.O. Box 5180 65726 Eschborn, Germany E [email protected] I www.euei-pdf.org

Authors: Economic Consulting Associates www.eca-uk.com and Carbon Africa www.carbonafrica.co.ke With comments and contributions by: Ministry of Energy and Petroleum, Energy Regulatory Commission, Kenya Power & Lighting Company Ltd, EUEI PDF, the Kenya Association of Manufacturers and other net metering stakeholders

Date of Publication: 5 March 2014

mailto:[email protected]

http://www.euei-pdf.org/

http://www.eca-uk.com/

http://www.carbonafrica.co.ke/

Kenya net metering assessment

Contents

i

Contents

Executive summary 1

1 Introduction 5

2 Overview of net metering 7

2.1 What is net metering and energy banking? 7

2.2 Why net metering? 9

3 The status of net metering in Kenya 11

3.1 Net metering law and policy in Kenya 11

3.2 Objectives of net metering in Kenya 12

3.3 Key issues to address 15

4 Lessons from net metering in other countries 16

4.1 Overview of international experience 16

4.2 Selection of country case studies 18

4.3 Country summaries 19

4.4 Key lessons learned 25

5 The potential market for net metering in Kenya 28

5.1 Eligible RE technologies 28

5.2 Solar PV costs and cost projections 29

5.3 Current situation in Kenya 31

5.4 Demand assessment in Kenya 33

5.5 Estimation of market size 38

5.6 Typical installation size 40

6 Lessons learned from existing PV projects in Kenya 42

6.1 Case study 1: SOS Children’s Village 42

6.2 Case study 2: UNEP 47

6.3 Case study 3: Uhuru Flowers 50

6.4 Lessons learned 53

7 The technical impact of net metering on Kenya Power 55

7.1 Impact on system load profile 55

7.2 Technical issues of solar PV grid interconnection 58

8 The economic impact of net metering on Kenya Power 59


Contents

ii

8.1 Approach to calculating the costs and benefits 59

8.2 Summary of the quantified benefits and costs 60

8.3 Calculation of benefits 61

8.4 Calculation of costs 65

9 The impact of net metering on government revenue 70

9.1 Value added tax 70

9.2 Other statutory levies 71

9.3 Alternative VAT & statutory levy scenario 72

10 Recommended net metering credits 73

10.1 Net metering credits calculated by customer category and year 73

10.2 Average net metering credit 74

10.3 Credits for other RE technologies 75

11 Recommendations on implementing a net metering programme 77

11.1 Phase 1of the programme 77

11.2 Phase 2 of the programme 79


Tables and Figures

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Tables and Figures

Tables

Table 1 Overview of countries with net metering policies 17

Table 2 Comparison of net metering policies in other countries 20

Table 3 Kenya solar PV system cost breakdown by component (USD) 30

Table 4 Small scale grid-connected PV projects in Kenya 32

Table 5 Solar PV LCOE for 2013 & 2018 and input assumptions 33

Table 6 Expected returns (IRR) of solar PV net metering systems 38

Table 7 Net metering uptake in other countries 39

Table 8 Maximum uptake of solar net metering per category 41

Table 9 Financial performance of SOS PV system WITH NEM 46

Table 10 Financial performance of SOS PV system WITHOUT NEM 46

Table 11 Financial performance of UNEP’s PV system WITH NEM 49

Table 12 Financial performance of UNEP’s PV system WITHOUT NEM 50

Table 13 Financial performance of Uhuru’s PV system WITH NEM 52

Table 14 Financial performance of Uhuru’s PV system WITHOUT NEM 53

Table 15 List of benefits and costs of net metering to Kenya Power 60

Table 16 Costs and benefits of net metering in USD ‘000 61

Table 17 Tariff structure for DC customers (<50 kWh/month) vs COSS 2013 requirements 66

Table 18 Difference in fixed/demand charge component in USD/kWh 68

Table 19 Net metering costs due to tariffs not reflecting fixed costs (USD ‘000) 69

Table 20 Net VAT and levy impact of net metering (export only) 71

Table 21 Net VAT and levy impact of net metering (all electricity) 72

Table 22 Net metering credit 73

Table 23 Net metering credit in equivalent tariff rates (USD/kWh) 74

Table 24 Net metering credits in USD/kWh equivalent 74

Table 25 Expected IRR of solar PV net metering systems (recalculated at 63% tariff) 75

Figures

Figure 1 Net energy metering 7

Figure 2 Metering alternatives 8

Figure 3 Solar PV individual generator size limits applied by Eskom 25

Figure 4 Investment cost split for grid-connected PV systems 30

Figure 5 PV cost projections 2013 - 2030 31


Tables and Figures

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Figure 6 Average daily solar radiation at 15 stations in Kenya from 1964-1993 35

Figure 7 Cash flow analysis for 365 kWp system offsetting electricity of CI1 consumer 37

Figure 8 Scenarios for net metering exported electricity rates 37

Figure 9 Projected maximum installed capacity for net metering solar PV 40

Figure 10 Measured power output from SOS PV system 43

Figure 11 Energy balance for SOS solar PV system 44

Figure 12 Power consumption, generation and grid exports for a week in Dec 2012 44

Figure 13 SOS’ electricity charges in 2012 45

Figure 14 Energy demand versus solar energy production at UNEP (2012) 48

Figure 15 Electricity charges to UNEP (Kenya Power electricity bills) 49

Figure 16 Output of solar energy system at Uhuru Flowers during one week 51

Figure 17 Effect of 100 MWp of solar PV on current load profile 55

Figure 18 Projected energy production and energy mix 57

Figure 19 Projected load profile and dispatch 2018 57

Figure 20 Costs and benefits of net metering 61

Figure 21 Power purchase costs for Kenya Power (2012) 62

Figure 22 Power dispatch 15 May 2012 63

Figure 23 Net metering and time of use cost of energy 65

Figure 24 Proposed tariff increase for CI1 customers (COSS 2013) 67

Figure 25 Simplified tariff projections for CI1 customers 68

Figure 26 Collection of VAT and statutory levies on hypothetical 365 kWp customer 71


Exchange rate

v

Exchange rate

1 USD = 87.5 KES (September 2013)


Abbreviations and acronyms

vi


AC Alternating current

CER Certified Emission Reductions

COSS Cost of Service Study 2013

ERC Energy Regulatory Commission

EUEI PDF European Union Energy Initiative Partnership Dialogue Facility

FiT Feed-in Tariff

GIZ Gesellschaft fuer Internationale Zusammenarbeit

GT Gas turbine

IRR Internal Rate of Return

KAM Kenya Association of Manufacturers

KES Kenya Shilling

KP / KPLC Kenya Power / Kenya Power & Lighting Company Ltd

KRA Kenya Revenue Authority

KTDA Kenya Tea Development Agency

kVA kilo Volt Ampere

kWh kilo Watt hour

kWp kilo Watt peak

LCOE Levelised Cost of Energy

LCPDP Least Cost Power Development Plan 2011-2031

MSD Medium speed diesel

MTP Electricity Sub-Sector Medium Term Plan 2012-2016

MVA Mega Volt Ampere

MWh Mega Watt hour

MWp Mega Watt peak

NEM Net Energy Metering

NEM credits surplus energy exported to the grid

NG Natural gas

NPV Net Present Value

PV Photovoltaic

RE / RES Renewable Energy Sources

REP Rural Electrification Program

RTAP Regional Technical Assistance Program

T&D Transmission and distribution



vii

ToU Time-of-use

US / USA United States of America

USD US Dollars

Var Voltage-ampere reactive

VAT Value Added Tax

Wp Watt peak


Executive summary

1

Executive summary

What is net metering?

Net metering allows grid-connected electricity consumers who also generate their own power to “bank” or “store” their electricity in times of over-production (i.e. for solar energy during peak production in the day), and to offset their grid consumption with this banked or stored electricity during other times (i.e. during night, morning and evening hours). Net metering is usually but not exclusively applied to small-scale generators using renewable energy sources.

There are a number of variations to net metering, particularly with respect to whether the utility pays for net exports to the grid. One option is for credits for excess electricity that is exported to the grid to be “banked”, such that any surplus is carried forward and used to offset consumption in future periods, but there is never any payment for net exports. Alternatively, net exports by net metering customers can be paid for (“settled”) by the utility on a periodic basis, either based on the billing period or less frequently such as quarterly or annually.

The potential market for net metering in Kenya

Our assessment is that there is a strong market for net metering in Kenya, particularly in the DC>1500, SC and CI1 customer categories. Households and businesses see net metering as being financially attractive (by cutting their electricity costs and hedging against electricity prices) and environmentally responsible. However, the actual adoption will depend on net metering programme features as discussed in this report and other external factors such as access to affordable long-term finance.

It is inherently difficult to forecast the uptake of net metering in Kenya, but we need to test the potential impact of net metering on the Kenya electricity system, so we estimate an upper bound of uptake based on experience in other countries. Under the most optimistic scenario, by 2018 Kenya could have net metering capacity installed that generates 100 MW at its peak. In reality, uptake will be significantly less than this, particularly if our recommendation that net metering systems be capped at 500 kW for phase 1 of the programme is applied (see below).

A net metering programme should apply to all renewable technologies, but in practice most net metering systems in Kenya are likely to be solar photo voltaic (PV). This is due to the fact that they can be sized to the individual system, are relatively easy to build and maintain and can be installed almost anywhere.

The effect on the system load profile

We estimate that the 100 MWp of solar net metering (which is the upper bound of possible uptake over the next 5 years) would make up less than 3% of the peak capacity in 2018 (and the energy contribution will be only 0.7%), and therefore the effect on the overall load profile will be negligible.


Executive summary

2

Net metering systems are expected to displace diesel, both at present given the current generation mix in Kenya, and also in the future given the mix forecast in the LCPDP for 2018.

Technical constraints

We do not anticipate any technical constraints on the introduction of net metering in Kenya. A frequency of 50 Hz can be technically controlled and actively supported by modern inverters. Modern solar PV technology can play an active role in voltage control and should not to be seen as an “additive” power resource. With weather forecasting and the geographically distributed nature of individual systems, PV becomes a predictable power resource with a very low default rate. Only a few additions to the Kenya Grid code would be needed.

Economic impacts on Kenya Power – October 2013 assumptions

A net metering programme will result in significant costs and benefits for Kenya Power. It is important to design a net metering programme in a way that compensates Kenya Power for its net costs. In establishing a net metering credit that is revenue neutral for the utility, possible impacts on non-participating ratepayers are also avoided.

By quantifying the key costs and benefits to Kenya Power with a focus on solar PV using October 2013 assumptions in an earlier version of this report, we determined that Kenya Power would fully recover its net costs if it gave a 63% credit for each unit of net metering electricity exported to the grid. In other words, net-metering customers will still pay the fixed component of the retail electricity tariff, but their energy consumption (which attracts unit costs and fuel charges) would be offset at by the electricity they have exported to the grid at a rate of 63%.

The costs of net metering to Kenya Power that we include in our calculation are (1) the difference in peak/off-peak electricity costs (the cost of energy imported from the grid at evening hours is more expensive than electricity exported during daylight hours), (2) administrative costs, and (3) net metering offsetting fixed costs due to current tariffs not properly reflecting them (due to a reluctance to increase fixed charges and demand charges sufficiently and impacts on cross subsidies). Of these we estimate that peak/off-peak costs and net metering offsetting fixed costs are most significant. Customer fees are proposed to help meet some administrative costs.

The key benefits of net metering to Kenya Power that we include in our calculation are (1) avoided energy purchases and (2) avoided T&D losses. The benefits of net metering would be higher if we also considered avoided capacity purchases, avoided T&D investments, and reliability benefits. However these are very difficult to quantify, given that there is little history or data on grid-connected solar PV in Kenya.

Economic impacts on Kenya Power – February 2014 update

The 2013 revision of the Schedule of Tariffs and an expected decrease in fuel costs necessitated a review of the net metering credit proposed in October 2013 to ensure no adverse economic impacts on Kenya Power and assess the effect on the financial attractiveness of net metering from the customer’s perspective. Other changes were also made to the economic model input assumptions to take into account relevant stakeholder comments.


Executive summary

3

The outcome of the revised assessment is a calculated 62% credit to maintain Kenya Power revenue neutrality based on the same cost and benefit parameters as above. The major change in the 2013 Schedule of Tariffs is a significant increase in the normative component of the variable tariff in the 2013 to 2015 period and minor increases to fixed and demand charges. This, however, is expected to be more than offset with a decrease in the Fuel Cost Charge, leading to lower customer electricity rates overall. We have also adjusted (a) the proportion of self-generation consumed on-site versus what is exported for domestic category customers, (b) avoided transmission and distribution loss benefits of net metering and (c) the impact of net metering on the tariff cross subsidy. The overall effect is a reduction in projected solar PV net metering customer returns by approximately 3.1% to 4.7% in commercial and industrial categories and by between 5.8% and 12.5% for residential users vis-à-vis the October 2013 scenario. While project returns remain positive in all cases, this clearly has an impact on the financial attractiveness of net metering and thus on potential uptake. However, it should be noted that this finding is sensitive to the anticipated Fuel Cost Charge reductions and any future tariff adjustments from 2016, and the extent to which these will differ in the long-term from the 2013 Cost of Service Study estimates that were the basis for the economic assessment. The changes are presented in a new Annex I of Volume 2 of this report.

The impact on VAT and other statutory levies

VAT exemptions for solar PV equipment were removed under the 2013 VAT Act and therefore VAT of 16% will be collected on the capital cost of solar PV. The VAT collected from solar PV equipment purchases will more than offset the VAT losses related to net metering transactions in the case that only exported electricity is considered. This is true for all categories of consumers at discount rates above 1%. If VAT losses on all transactions (exports and reduced consumption) are considered, the impact on government revenue is negative. However, input and output VAT balancing by corporate customers has not been taken into account, which would likely make the actual impact more nuanced.

In both cases, there will be losses in ERC and REP levies, but these are expected to be relatively minor. Similarly, the impact on the new Water Levy and Security Support Facility should be minimal.

Phase 1 of a net metering programme

Because our analysis shows that there are no significant technical impacts associated with net metering in Kenya, and that Kenya Power can be fairly compensated for the net costs it will incur, we recommend launching phase 1 of a net metering programme.

In keeping with best practice internationally, phase 1 should be reasonably conservative and used to test the concept, before widening eligibility for the programme and increasing its sophistication. An appropriate time period for phase 1 could be two to three years.

We recommend that it have the following features:

During phase 1, net metering electricity can be banked (i.e. any surplus is carried forward and used to offset consumption in future periods), but no payments are made for surplus generation. This keeps the programme administratively simple to implement, easy for customers to understand, and clearly delineates net metering from feed-in tariffs (FiTs) which are paid for renewable electricity generation by larger producers.


Executive summary

4

As discussed above and presented in Annex 1 of Volume 2 of this report, banked electricity should be credited at 62% of the variable component of the retail electricity tariff.

Only allow systems sizes of 500 kW or less to participate in phase 1. This avoids confusion with the FiT (which applies to systems above 500 kW, or 200 kW in the case of biogas) and avoids dealing with the more involved technical requirements of larger systems. Furthermore, the individual system size should be limited to the existing contract or demand size. This is to prevent oversized systems that may operate as net exporters and to minimize the need for distribution network upgrades.

Programme eligibility for all renewable energy technologies.

The total capacity eligible for net metering should be capped at 100 MW. We do not expect that this cap will be reached any time during the next five years (let alone during the shorter phase 1 period), but it serves as a means of limiting the impact in case uptake is much higher than expected. The net metering cap would be separate from and additional to the technology-specific caps in the Feed-in Tariff Policy.

Phase 2 of a net metering programme

The following changes to the net metering programme should be considered in phase 2:

Allow ‘settlement’ for net metering exports by customers who opt into the scheme, in addition to offering the existing ‘banking’ option. In other words, customers will have to options to choose from: (1) bank their exported energy and offset it against future consumption (as proposed under Phase 1), or (2) get paid a per kWh tariff by Kenya Power for their net exports.

Increase the individual cap on system size (500 kW), to allow participation of larger customers.

Increase or remove altogether the cap on total net metering capacity (100 MW)

Recalculate the value of net metering credits (62%), making use of significantly more data, which will then be available.

Consider simplified approval procedures for proposed net metering facilities that meet certain requirements (e.g. systems of 10 kW or less that do not inject more than 15% of shared feeder line capacity could receive automatic approval with no utility site visit).

Next steps

To make the net metering pilot programme operational, the next step will be to finalise net metering regulations and application procedures, draft documents for which are submitted along with this report. The drafts are based on best practice in other countries, drawing on materials provided in annexes to this report (provided in Volume 2).


Introduction

5

1 Introduction

This net metering assessment report has been prepared by a team of consultants from Economic Consulting Associates, the Kenya Association of Manufacturers and Carbon Africa Limited as part the 2013 Renewable Energy Regulatory Capacity Development project supported by the European Union Energy Initiative Partnership Dialogue Facility (EUEI-PDF).

The assessment was undertaken in response to a request from energy sector stakeholders in particular the Ministry of Energy and Petroleum, the Energy Regulatory Commission and Kenya Power.

Objective of this report

The main objective of the report is to assess the likely technical and economic impacts of the adoption of a net metering programme in Kenya and, where needed, identify measures that could be implemented to address issues that may arise. The study findings are intended to inform the drafting of net metering regulations.

Approach

The report is based on an analysis of data and information available as well as international experience on net metering. An earlier 2011 net metering study commissioned by Gesellschaft fuer Internationale Zusammenarbeit (GIZ) and stakeholder comments have also been taken into account.

A new Schedule of Tariffs was approved by ERC in November 2013 and gazetted in January 2014. This development necessitated an update of the economic assessment to ensure no adverse impacts on Kenya Power and assess the effect on the financial attractiveness of net metering from the customer’s perspective. The update also considers additional stakeholder comments received since October 2013. The changes are described in Annex 1 of Volume 2 of this report.

Report structure

The remainder of this report is structured as follows:

Section 2 gives a brief overview of net metering concept

Section 3 summarises the current status of net metering in Kenya

Section 4 reviews a number of different international examples of net metering and draws out key lessons to be learned

Section 5 assesses the size of the potential market for net metering in Kenya

Section 6 reviews three different existing solar PV projects in Kenya and draws key lessons learned for a net metering programme


Introduction

6

Section 7 assesses the technical impact that net metering may have on the national grid

Section 8 assesses the economic impact that net metering is likely to have on Kenya Power based in information available as of October 2013. The assessment is updated to incorporate the Schedule of Tariffs gazetted in January 2014 and additional stakeholder comments and is presented in Annex 1 of Volume 2.

Section 9 assesses the impact that net metering is likely to have on government revenues such as VAT

Section 10 recommends a net metering tariff that will ensure that Kenya Power is not negatively impacted by net metering

Section 11 sets out the next steps for implementing a net metering programme in Kenya.

Annexes 2-7, provided in Volume 2 of this report, give additional information, including a proposed application and approval process and guidance on technical standards.


Overview of net metering

7

2 Overview of net metering

2.1 What is net metering and energy banking?

Net metering (also known as Net Energy Metering or NEM) is a policy that permits a electricity customer to generate electricity on site to offset its load, and to deliver any excess electricity to the utility at other times.

Net metering, in essence, allows decentralised producers of power primarily for own consumption to “bank” or “store” their electricity in times of over-production (e.g. for solar energy during peak production in the day) in the national grid, and to balance out their grid consumption with this banked or stored electricity during other times (e.g. during night, morning and evening hours). Net metering is usually but not exclusively applied to small-scale generators using renewable energy sources. The concept is presented in Figure 1.

Figure 1 Net energy metering

Adapted from GIZ 2011

Different ways to treat net electricity exports

The surplus electricity exported to the grid is referred to as net metering credits. One important aspect of net metering is the treatment of these credits at the end of a billing period. In this respect, there are three approaches that can be applied:

Net energy “banking”: Net metering, with “banking” of surplus electricity with carry forward for a given period. In this approach there is never any payment for surplus exported, which is forfeited after the expiry of the crediting period.

Net settlement: Net metering, with periodic “settlement” – normally quarterly or annually – of any surplus through payment by the utility for any remaining credits carried forward.



8

Net billing: Net metering, with immediate (within the billing period) payment from the utility to the customer for any surplus exported. This approach starts to blur the lines between net metering and a Feed-in-Tariff.

Some countries apply a combination of the above approaches, for example net energy “banking” for residential and “settlement” for commercial or industrial customers. There are also slight design variations, such as multi-site net energy banking where surplus electricity exported can be drawn in a different location by a related entity. For example, surplus units supplied by SOS Children’s Village Mombasa could be credited to SOS Children’s Village Nairobi.

Metering alternatives

Net metering is usually associated with the electricity meter running both ways, i.e. running forward when consuming electricity from the grid and backwards when exporting surplus electricity to the grid. If the system is sized according to the facility’s consumption, the meter at the end of a period should be zero. This suggests that electricity imported from the grid and exported to the grid has exactly the same value. In Section 11 we propose that imports from and exports to the grid are metered separately. This way, records will be available for both import and export streams and different tariffs can be applied to each.

Figure 2 Metering alternatives

Meter running backwards Separate metering for exports and imports

Adapted from GIZ 2011

Key advantages

Net metering is associated with a range of advantages:

Generation of additional power in the national grid, without the need for investment by the utilities or conventional IPP’s

Promotion of small scale investments, value addition and market development

No direct payment by the grid operator (as opposed to a FiT), depending on the specific mechanism applied



9

Consumer savings on power bills

Due to these and other benefits, more than 40 countries around the world have adopted net metering.

2.2 Why net metering?

Of the more than 40 countries and 50 US states and overseas territories that have adopted net metering, the rationale and/or policy impetus for such varies depending on the country’s circumstances and priorities. In Section 4 below we review net metering experience in 11 different countries. From this, five main objectives for implementing net metering emerge:

Promotion of renewable energy. Net metering is viewed by all countries surveyed as a means by which countries can achieve renewable energy targets or increase the share of renewables in the grid mix and reduce fossil fuel use for power generation.

Facilitation of economic development, technology innovation, local industry and job creation. California, Denmark, Sri Lanka, Tunisia and Uruguay note this rationale.

Local ownership of, and customer investment and participation in, energy services. Indicated by California, Denmark, Sri Lanka and Tunisia.

Energy security, diversification and self-sufficiency. Policy impetus in California, Denmark, Morocco and Sri Lanka.

Reduce greenhouse gas emissions. Cited by California, Denmark, South Africa and Uruguay.

Additional objectives underlying net metering in different countries include:

Build on successful rural electrification, water pumping (solar PV, small hydro) and solar hot water heating programmes (Morocco, Sri Lanka, Tunisia).

Reduce electricity demand (California, South Africa).

Other environmental benefits (California, Morocco).

Make use of distributed renewable energy at different scales (Uruguay, Jamaica).

Reduce electricity interconnection and administrative costs (California).

Reduce customer electricity bills (Morocco).

Innovative leadership (California).

Support a clean economy in general (California).

Reduce transmission and distribution losses (Jamaica).



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Contribute to well-defined and established governance, institutional, legal and regulatory framework in the energy sector (Jamaica).

Some countries or regions see net metering as a policy instrument that can be used to achieve very specific targets for distributed renewable energy uptake, notably in California (3,000 MW solar PV), Denmark (200 MW solar PV) and Tunisia (15 MW solar PV).


The status of net metering in Kenya

11

3 The status of net metering in Kenya

3.1 Net metering law and policy in Kenya

Existing policy

Kenya’s current policy on energy is contained in Sessional Paper No. 4 of 2004. Net metering, however, does not feature in this policy document. On 28 January 2011, the Permanent Secretary, Ministry of Energy, set up a Task Force made up of various stakeholders within the Energy Sector with the mandate to review the Energy Policy (Sessional Paper No. 4 of 2004), the Energy Act 2006 and related subsidiary legislation and to align them with the Constitution. The Task Force has since finalized the draft revised Energy Policy, and this new policy, unlike its predecessor, contains provisions on net metering.

The draft Energy Policy defines a net metering system as:

“a system that operates in parallel with the electrical distribution facilities of a public utility and measures, by means of one or more meters, the amount of electrical energy that is supplied. It is an incentive for consumers of electrical energy to sell renewable energy generated electricity to a retailer or distributor as the case may be.”

The policy further contains the following provisions on net metering:

The Government aims to employ, as one of the policies and strategies to address the challenges faced for solar energy1 and wind energy,2 the provision of a framework for connection of electricity generated from solar energy and wind energy to national and isolated grids, through direct sale or net metering.

The Government plans to develop a tariff for net metering for electricity generated from renewable energy sources by electricity consumers as a strategy to deal with the challenges facing the adoption of renewable energy resources in the country.3

The Government aims, under the policy’s Agenda for Action, to develop in the short term (from the year 2012-2016), necessary legislation for net metering.4

The Task Force has also drafted the required Energy Bill that is intended to align Kenya’s energy laws with the Constitution, and will replace the current Energy Act, 2006. Unlike the Energy Act, which does not contain detailed provisions on net metering, the Energy Bill from the onset highlights net metering. In its preamble, the Bill states that it is intended to be an Act of Parliament to inter alia provide for directorates within the Ministry responsible for energy, net metering, promotion of renewable energy and for connected purposes.

1 Gok (2013) National Energy Policy Final Draft, Ministry of Energy, Republic of Kenya, Section 3.7.3 (4)

2 Ibid, Section 3.8.3 (5)

3 Ibid, Section 3.13.2 (b)

4 Ibid, Section 9.9.1.3 (2)



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Section 2 of the Bill proceeds to define a “net-metering system agreement” as,

“an agreement entered into in accordance with section 157 by a distribution licensee or retailer and a renewable energy generator of capacity not exceeding twenty kilowatts or such other limit as may be prescribed by the Cabinet Secretary.”

The section further defines a “net-metering system” as,

“a system that operates in parallel with the electrical distribution facilities of a distribution licensee and that measures, by means of one or more meters, the amount of electrical energy that is supplied:

i. by the distribution licensee or retailer to a consumer who owns the renewable energy generator, and

ii. by the consumer who owns the renewable energy generator to the distribution licensee or retailer.”

According to the Bill,5 net metering will be available to a consumer who:

Owns a renewable electrical energy generator of a capacity not exceeding twenty Kilowatt or such other limit as may be prescribed by the Cabinet Secretary;

Applies to enter into a net-metering system agreement to operate a net-metering system with a distribution licensee or retailer; and

Has a renewable energy generation facility that is located in the service area of the distribution licensee or retailer with whom he applies to enter into a net- metering system agreement.

Each distribution licensee or retailer shall make available net metering services to any electric consumer who fulfils the above-mentioned conditions, in accordance with the net metering regulations.6 The Cabinet Secretary responsible for Energy, upon recommendation of the National Energy Regulatory Commission, shall enact these regulations.7

The final draft Energy Policy and Energy Bill have been submitted to Parliament, and are among the list of bills to be fast-tracked by lawmakers.8 However, until the policy is approved, the bill becomes law, and the Cabinet Secretary makes net metering regulations, the provisions on net metering will remain non-operational. As noted in section 1 above, this assessment has been prepared to help inform the formulation of such regulations.

3.2 Objectives of net metering in Kenya

Despite these advancements in the law and policy related to net metering, there is no written Kenyan purpose statement or statement of objective for net metering. As such, the purpose and

5 Section 157 (1)

6 Section 157 (2)

7 Section 158 (1) and (2)(b)

8 Email communication from Energy Regulatory Commission (ERC) legal department, received on 6 August 2013



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objective of net metering in Kenya can either be implied from the stated overall objective of the draft energy policy which is to ensure affordable, sustainable and reliable supply to meet national and county development needs, while protecting and conserving the environment, or the policy’s more specific stated goals which include inter alia:9

Improvement of access to quality, reliable and affordable energy services;

Promotion of healthy competition in the sector;

Protection of consumer interests, and

Generation of at least 70% of electricity from clean or renewable resources.

In addition, the Constitution of Kenya 201010, though not making specific mention of net metering, also provides an implied rationale for the state’s pursuit of this policy instrument. According to Article 69 (1), the state shall inter alia encourage public participation in the management, protection and conservation of the environment,11 and the state shall also eliminate processes and activities that are likely to endanger the environment.12 By allowing and encouraging small-scale renewable energy power producers to generate power from renewable sources for their own use and for supply to the grid, net metering ensures that the two afore-mentioned constitutional objectives are met. Similarly, to achieve Vision 2030, which is Kenya’s long-term development blueprint, the Government has committed to establishing a strong regulatory framework, and encouraging more private generators of power.13 This commitment can be partially met through allowing net metering and setting up the requisite policy and regulatory framework for it.

Finally, regulations under the 2006 Energy Act such as the 2012 Energy (Solar Water Heating) Regulation, the 2012 Energy (Solar Photovoltaic Systems) Regulations, and the 2012 Energy (Energy Management) Regulations14 also implicitly provide justification for net metering. The Solar Water Heating Regulations make it mandatory for all premises within the jurisdiction of a local authority with hot water requirements of a capacity exceeding one hundred litres per day to install and use solar heating systems (unless otherwise exempted). These regulations therefore encourage consumers to embrace energy production for own consumption from renewable sources. The solar photovoltaic regulations further facilitate the licensing of solar technicians who are instrumental in the installation of the solar system for consumers. The Energy Management Regulations are also indirectly relevant to net metering as through these regulations the government aims at ensuring consumers achieve energy efficiency and conservation. Such demand-side management reduces utility electricity sales to individual customers, similar to net metering.

9 Section 1.2 (2)

10 GoK (2010) The Constitution of Kenya, available at www.kenyalaw.org (accessed on 3 August 2013)

11 Article 69(1) (d)

12 Article 69 (1) (g)

13 GoK (2007) Kenya Vision 2030: The Popular Version, section 3.5, available at http://www.vision2030.go.ke/index.php/home/library (accessed on 5th August, 2013)

14 Available at http://renewableenergy.go.ke/index.php/content/19 (accessed on 6th August, 2013)

http://www.kenyalaw.org/

http://www.vision2030.go.ke/index.php/home/library

http://renewableenergy.go.ke/index.php/content/19



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Kenyan stakeholder comments on the objectives of net metering

Based on consultations with stakeholders, some proposed objectives of net metering in Kenya are to:

Increase electricity supply while diversifying the sources of power.

Increase renewable energy production.

Reduce the need for future capacity additions at higher cost.

Promote Kenya’s economic growth by allowing for other uses of power.

Help with the move to time of use tariffs, with a focus on industrial/large commercial customers moving towards business during off-peak.

Help to build the electricity market with a view to competition and benefits for other parts of society/industry.

Learning from other countries’ experience as presented in Section 2.2 above, the top two cited objectives for net metering are to: (a) increase generation from renewable sources and (b) help foster economic development, technology innovation, local industry and job creation. The first objective is considered for Kenya in Annex 3 of Volume 2 of this report.

Example of potential wider economic benefits in Kenya

In agreeing on the objectives of net metering, which is outside of the scope of this study, it may be useful to consider the potential wider or indirect benefits. International examples of economic and development benefits are presented in Annex 3 of Volume 2 of this report.

Such benefits have not been assessed for Kenya due to a number of uncertainties. However, an indication in terms of potential job creation in Kenya can be derived from the Tunisian example where the uptake of 1.3 MWp of solar PV by 739 net metering customers from 2009 to early 2012 reportedly led to the establishment of 30 new solar PV installation companies and provided the impetus for a PV manufacturing facility with an annual capacity of 25 MWp, the first unit of which is operational.15

The US experience shows that of the approximately 8,800 solar PV installation companies nationwide, 74% are very small employing only 2-3 workers16. Based on the Tunisian example, in the early years before market consolidation an installation company is established for every 25 new customers. Extrapolating to Kenya, in the maximum uptake scenario (see Table 8 below) of 15,821 individual systems in the DC and SC categories, 633 new PV installation companies may emerge creating almost 1,600 jobs if an average of 2.5 employees per company is assumed.

15 Missaoui, Rafik and Sami Marrouki (Décembre 2012) Etude sur les mécanismes innovants de financement des projets d’énergie renouvelable en Afrique du Nord. Rapport final pour l’Economic Commission of Africa, pp. 60-61.

16 Cornell University ILR School and BW Research Partnership (November 2012) National Solar Jobs Census 2012: A Review of the US Solar Workforce, a report for The Solar Foundation, p. 24.



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3.3 Key issues to address

In general, when planning the design and implementation of a net metering policy a number of factors need to be considered. Most important among these is assessing the potential impact and weighing the costs and benefits in line with the policy goals and the different stakeholder expectations. Furthermore, a net metering programme should be designed in such a way that it facilitates adoption by customers but is stringent enough that technical, safety and other requirements are met.

These general considerations are indeed relevant in the case of Kenya. Furthermore, a number of specific issues to be addressed have been noted:

The 2013 draft Energy Bill specifies that there will be net metering regulations and a tariff for net metering – if the Bill is adopted by Parliament, both items will need to be developed before net metering can be activated.

The draft Bill indicates a proposed individual system limit of 20 kW, at least in the first instance. While this needs to be borne in mind, the market potential and appropriateness of a system size limit should be evaluated. The aggregate impact of net-metered systems is also relevant.

Along with the extent of potential uptake, the timing of such is important. With expected low-cost large hydro imports from Ethiopia and planned geothermal projects benefiting from economies-of-scale, would distributed generation under net metering still help to meet capacity adequacy and/or displace fossil fuel power plants in the margin in the future?

International experience indicates some benefits from net metering, such as reduced transmission and distribution losses. These need to be assessed for Kenya where data availability allows.

There is likely to be “lost” revenue for the utility in terms of reduced electricity sales as well as differences in costs between energy banked off peak and withdrawn at peak time, possible lack of coverage of the costs of providing security of supply to net metering customers and loss of contributions to the cross-subsidy pot among others. These need to be quantified and compensated for while not complicating the existing tariff structure and billing arrangements.

Lost revenue also for government in the form of a decrease in VAT, ERC levies and Rural Electrification Program need to be estimated and if relevant justification for such in terms of programme benefits may need to be presented.

On the other hand, the tax regime for renewable energy equipment and any compensation made by net metering customers to the utility will play a key role in determining the financial attractiveness and adoption of net metering from the customer’s perspective.


Lessons from net metering in other countries

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4 Lessons from net metering in other countries

4.1 Overview of international experience

The concept of net metering originated in the United States in 1983, due to requests from grid-connected customers with micro-solar PV and wind facilities.17 The first formal pilot programme was established in 1995 and begun implementation in 1996 in California. Denmark became the second country to adopt a pilot programme in 1998.

As of August 2013, there are at least 40 countries around the world that have adopted some form of net metering in addition to 46 US states, the US District of Columbia and four US overseas territories.18 These countries and jurisdictions encompass a range of geographic, demographic and economic circumstances. Other countries such as the United Kingdom, Germany and Thailand have opted for more of a “Feed-in-Tariff” approach to the off take of surplus electricity from distributed small generation, even at the residential scale. Some countries have adopted more than one mechanism.

In terms of recent developments, in 2012 three new countries enacted net metering policies:

Brazil, for small-scale power generation of 1,000 kW or less

Chile, with a net billing legislation for renewables up to 100 kW

Egypt, adopted at the end of 2012

In the same year, there were also notable revisions to existing policies:

The US state of California almost doubled the number of systems allowed under net metering up to approximately 5,200 MW

The US state of Massachusetts doubled the aggregate cap for its solar net metering programme to 6% of peak demand

Denmark reduced support for new solar PV installations under net metering, including by limiting support to 10 years and reducing the guaranteed prices paid for surplus electricity19

An overview of countries with net metering, net settlement or net billing policies is provided in Table 1 below.

17 Curran, Patrick and Gerrit W. Clarke. December 2012. Review of Net Metering Practices. Camco Clean Energy report to the Electricity Control Board of Namibia.

18 Renewable Energy Policy Network for the 21st Century (REN21). Renewables 2013: Global Status Report, pp. 80-82 and authors’ own research

19 REN21. Renewables 2013: Global Status Report, p. 73 and authors’ own research



17

Table 1 Overview of countries with net metering policies20

High income Upper middle income Lower middle income

Barbados Brazil Cape Verde

Belgium Chile Egypt

Canada Costa Rica Guatemala

Cyprus Dominican Republic India

Denmark Grenada Lesotho

Italy Jamaica Micronesia

Japan Jordon Pakistan

Malta Lebanon Philippines

Netherlands Mexico Sri Lanka

New Zealand Morocco Syria

Portugal Panama Tunisia

Singapore South Africa

South Korea St. Lucia

Spain21

Uruguay

United States of America Thailand22

In the majority of the cases net metering is provided for at the national level. In some countries net metering has been adopted instead at the state, utility or municipal level although there is usually a national policy to encourage such.

Net metering programme rules vary widely among countries on issues such as aggregate cap, individual facility size, treatment of excess generation and measures for customer or utility compensation.

Nevertheless, there are also some common themes such as:

Starting with a restricted/pilot approach and expansion thereafter

Individual system size or maximum output is capped at the customer contract size

Simplified application/implementation procedures for small-scale systems

Interconnection and system technical and safety standards

20 REN21. Renewables 2013: Global Status Report, pp. 80-82 and authors’ own research

21 Spain’s net metering programme was temporarily suspended for new applicants in 2011.

22 Thailand established what can be considered a “net billing” programme in 2002 under a Very Small Power Producer (VSPP) framework. However, with a first amendment in 2006 while the billing structure reminded largely the same the addition of a price premium saw the programme evolve into what is in essence a Feed-in-Tariff and the type of projects implemented thereafter reflect this.



18

Application fees and new meter costs charged to the customer

No utility compensation where the net metering policy is based on strong support for renewable energy generation. Otherwise a mechanism for utility compensation is normally established.

No net metering customer compensation for “deemed” generation

Periodic regulatory review and policy revisions

Generally the differences noted depend on the country’s situation in particular regarding the power sector, the policy objective behind net metering, the availability of financial incentives and the extent of concern over impacts on the utility and/or other ratepayers.

Kenya would be the first “low income” and “low electricity access” country in the world to adopt net metering.

Most countries and utilities have faced or are facing similar issues and considerations as have been identified in Kenya. Different approaches and solutions are being implemented, reviewed and revised as countries gain experience with net metering. Kenya may be able to learn from such examples.

4.2 Selection of country case studies

From those listed in Table 1 a selection of 11 countries was chosen for further analysis. Relevant findings are presented to help inform the discussion in Kenya.

The selection was based on a country’s (a) long-term or extensive net metering experience, (b) comparativeness with the Kenyan situation and/or (c) presence of interesting design features. Furthermore, at least two examples of high, upper middle and lower middle-income countries are included.

High income:

Denmark, due to its extensive experience

USA, due to its extensive experience

Upper middle income:

Brazil

Jamaica, as an isolated grid system

Mexico

Morocco, as an African example

South Africa, as an example from sub-Saharan Africa



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Thailand, as the first developing country to adopt net metering

Uruguay, due to a number of similarities with the Kenyan power sector

Lower middle income:

Tunisia, as an African example

Sri Lanka, due to a number of similarities with Kenyan power sector

Out of the countries reviewed, the Sri Lankan case corresponds most closely to the Kenyan situation in terms of the power sector: installed capacity, peak demand, generation mix, load profile and retail electricity prices. Sri Lanka also has almost six years of experience with net metering, starting with a low capacity cap that was recently raised. Sri Lanka has achieved moderate success in net metering uptake with no subsidies or direct financial incentives. The country may thus provide the most relevant example for Kenya to take into account.

Detailed case studies of the countries are provided in Volume 2 of this report.23.

4.3 Country summaries

A summary of the approach to net metering in each of countries reviewed is provided in order of the year of adoption, with a focus on unique design features. Some achievements and challenges are reported in the next sub-section below.

References are provided in the detailed country overviews in Volume 2 of this report, unless otherwise referenced in this section. Volume 2 includes the country macroeconomic and power sector situation for reference vis-à-vis circumstances in Kenya, information on the type of policies, legislation and regulatory frameworks in place, any incentive mechanisms available, a summary of achievements and challenges and specific design features.

Table 2 below gives a snapshot comparison of the main net metering programme design characteristics. All countries reviewed fix an individual system cap, either per customer category or based on the extent of the procedures customers must follow. The latter is presented in brackets in the “facility cap” item in the table. A key to the abbreviations used is as follows:

Y Means yes – indicating the presence of a feature

N Means no – denoting the absence of a feature

Y & N Means the feature applies to one or more customer categories or project types but does not apply to others

n/a Means information on the feature was not available

? Means the information available was not clear

23 Some information from the Thai experience is also included in this section but a detailed annex ha not been prepared as since from 2006 what would have previously been considered a net metering programme evolved into more of a Feed-in-Tariff



20

Table 2 Comparison of net metering policies in other countries

Cal

ifo

rnia

19

95

De

nm

ark

19

98

Thai

lan

d

20

02

Tun

isia

20

04

Me

xico

20

07

Mo

rocc

o

20

09

Sri L

anka

20

09

Uru

guay

20

10

S A

fric

a

20

11

Jam

aica

20

11

Bra

zil

20

12

Approach Net “banking” Y Y N Y Y N Y Y Y N Y Net settlement or billing Y Y Y N Y Y N Y Y&N Y N

Eligible technologies All or most renewables Y Y Y Y Y Y Y Y Y Y Y Cogeneration eligible Y Y Y Y Y Y N? N Y Y Y

Eligible customer categories Residential Y Y Y Y Y Y Y Y Y Y Y Commercial Y Y Y Y Y Y Y Y Y Y n/a Industrial/ other Y Y Y Y Y Y Y Y N N n/a

Facility cap (MW or %) Residential (or simplified) 0.03 0.006 10.0 Contract 0.01 0.02 10.0 0.01 0.10 0.01 0.10 Commercial (or “fast track”) 2.00 1.500 10.0 30% 0.50 2.00 10.0 0.15 0.10 0.10 1.00 Industrial (or other) 5.00 10? 10.0 30% 0.50 50.0 10.0 0.15 n/a n/a 1.00 Aggregate cap (% peak demand) 5% No limit n/a No limit n/a No limit 10% n/a n/a 2% No limit

Contract Contract duration (years) No limit 10-20 No limit No limit No limit 25 20 10 No limit 5 No limit Simplified procedures Y Y Y & N Y Y n/a Y Y Y & N N Y “Multi-site banking”/ wheeling Y N? n/a Y N n/a N n/a N N Y

Utility compensation Application fee Y N n/a Y n/a n/a Y n/a Y Y N Meter cost/ installation fee Y Y Y N Y n/a Y Y Y Y Y Impact assessment (if needed) fee Y Y & N n/a N n/a n/a Y n/a Y & N Y N Fixed or standby charge N N Y N n/a Y N N Y N N Interconnection charge N Y & N Y N n/a n/a N N N N N Time of use or differential tariff Y & N N Y Y & N Y Y N N Y Y Y Administrative or other fee Y Y Y N n/a n/a N N N N N

Other Retail tariff (High, Med, Low) M H M M/L M/L M/L H/M H M/L H H/M Incentives/ subsidies Y Y Y Y & N Y N N N N N Y & N “Success” in terms of uptake Y Y Y Y n/a n/a Y n/a Pilot Pilot Not yet



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United States of America (1995)

In the US, net metering is adopted at the state-level under the encouragement of the federal policy for state regulators. 46 of the 50 US states (including those with utilities with voluntary programmes), the District of Columbia and four US overseas territories, namely Puerto Rico, Guam, Virgin Islands and American Samoa have implemented net metering.

In most US states, all renewable energy types are eligible, including, where applicable wave, tidal, ocean and fuel cell-generated power. Three of the states have no limits on individual system size. The rest range from 20 kW – 80 MW, with most in the range of 100 kW – 1 MW. Aggregate net metering caps are generally 1-6% of peak demand. California as the most advanced US state was the focus of the US country review. Some notable features from the California example include:

Automatic approval procedures for systems up to 30 kW, “fast-track” procedures up to 2 MW and the requirement for individual system impact studies for larger systems.

Provisions for virtual and aggregate metering. Permission for “multi-site banking” in the case of government offices and universities only.

A ban on net metering and distributed generation in general from "secondary networks" where parallel systems are in place to improve reliability in dense urban areas. Here transformers are not configured to handle back-feeding (which net metering export would stimulate) and network protection equipment may not handle automatic disconnect.

In the USA, a number of studies on the cost impacts of net metering on utilities and other rate payers have found different results ranging from (a) net benefits, (b) no impact, (c) minimal impact or (d) some impact, worthy of utility compensation mechanisms. The difference seems to mostly come from what parameters are considered in the study and some of the input assumptions, as well as whether it is the utility, the regulator or industry associations who commissioned the study. In California, a September 2013 Assembly Bill to restructure electricity rates and allow scope for expanding net metering passed unanimously and was seen by all stakeholders including utilities, net metering participants and rate payers as a positive and balanced compromise. The Bill included scope for utility identification of priority locations where net metering could best support the grid.24

Denmark (1998)

Denmark has some of the highest residential electricity prices in the world and there are relatively strong subsidy programs to support net metering as well as a range of rules and compensation mechanisms for customers depending on factors such as system size and technology type. As with California, Denmark has “automatic” approval procedures for systems up to 6 or 11 kW and fast-track application procedures up to 1.5 MW, with separate procedures for wind generators above 11 kW. Solar PV up to 6 kW receives a separate treatment in Denmark as it does not receive any payment for surplus power generated, but only offsetting against the customer bill (“banking”). All other technologies received periodic payment for any surplus (“settlement”. In Denmark the utility is compensated for any revenue impacts first by taking advantage of any differential between the net

24 Governor’s Wind Energy Coalition website. 16 September 2013. “In sweeping re-write, Calif. overhauls rates, lifts net metering cap.” http://www.governorswindenergycoalition.org/?p=6618

http://www.governorswindenergycoalition.org/?p=6618



22

metering tariff and any upside on the Nord Pool spot market and then in the form of a renewable energy surcharge applied to the electricity tariff of all customers. The compensation is adjusted quarterly. Denmark is the only country among those reviewed to have no individual contract duration. Instead, the contract period is fixed in each revision of the net metering regulation and guaranteed for all systems installed under that revision, even if the net metering rules change in subsequent years.

Thailand (2002)

Thailand was one of the first countries and apparently the first developing nation to adopt a form of net metering in May 2002. Thailand’s initial individual system cap was set at 1 MW net maximum outflow to the grid and took a net billing approach where the price offered for surplus generation was the same as what distribution utilities paid to purchase power from the transmission utility, being roughly 80% of the average retail rate, with time-of-use. In the 3rd quarter of 2006 the purchase price was EUR 0.08/kWh during peak hours (09:00-22:00) and EUR 0.04/kWh during off peak. In 2006 the programme was expanded to allow for systems up to 10 MW, combined heat and power plants and an export tariff subsidy was added25. These changes effectively amended the policy from net metering to a Feed-in-Tariff approach, resulting in 590 MW of distributed renewable generation from systems up to 10 MW as of December 2011.26 The following challenges were noted with regards to net metering and subsequently the Feed-in-Tariff policy that emerged therefrom:

Oversubscription due to the overly-generous subsidies that were added in 2006 and over achievement of solar and biogas targets

Increasingly complicated application and connection procedures, especially for projects above 100 kW, which was seen as an attempt by utilities to block such projects

Poor integrated planning of small-scale RE systems

Tunisia (2004)

Tunisia as the first African county to have implemented net metering has a programme that focuses on (a) solar PV systems at the residential level and (b) self-generation in the industrial sector. In addition to system caps, the individual system limit is the customer contract size and net metering customer export may not exceed 30% of self-generation except in the case of biomass power where the cap is fixed at 15 MWel. Tunisia’s net metering policy allows for both power wheeling and "multi-site banking".

Mexico (2007)

In Mexico, the maximum system size is up to 500 kW and any surplus can be sold to the utility at 85% of the customer's normal rate or credit can be carried forward for 12 months. The net metering

25 Greacen, Chris. “Thailand gives the go-ahead to distributed energy.” Cogeneration and On-Site Power Production, March-April 2007 edition, pp. 65-73.

26 Tongsopit, Sopitsuda and Chris Greacen. “An assessment of Thailand’s feed-in tariff program.” Renewable Energy 60 (2013), p. 443. http://www.wind-works.org/cms/fileadmin/user_upload/Files/Chabot_Files/Tongsopit_Greacen_2013_An_Assessment_of_Thailand_s_FiT_Renewable_Energy.pdf

http://www.wind-works.org/cms/fileadmin/user_upload/Files/Chabot_Files/Tongsopit_Greacen_2013_An_Assessment_of_Thailand_s_FiT_Renewable_Energy.pdf





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scheme allows for time-of-use metering for existing time-of-use customers. Since net metering was introduced in 2007, the model contract has been updated twice in order to better suit renewable energy technologies and its users. Moreover, the specific framework is complemented with other relevant renewable energy policies and procedures such as a preferential transmission tariff for power sourced from renewable energy sources and investment incentives including an accelerated depreciation scheme and a special financing programme for small-scale generation. New meters required for net metering are installed by the utility but the customer is charged for the difference with respect to the cost of the normal meter. Any additional meters may be installed at the generator’s own cost.

Sri Lanka (2009)

Sri Lanka’s net metering policy, established in January 2009, was built on successful experience with off-grid electrification, with 300 village-level small hydro schemes totalling 4.5 MW supplying 7,000 households and 160,000 solar home systems totalling more than 5 MWp. Supplementary to the country’s Feed-in-Tariff, net metering was seen as a way to increase green energy uptake “easily”. In the initial phase an individual installation cap of 42 kVA was set. This was increased to 10 MW in July 2012, with an aggregate system limit of 10% of demand. In Sri Lanka as with some other countries the equipment installation company often takes the lead making the application to the utility for net metering. There is no time-of-use tariff. Carry forward of surplus credits is allowed up to 10 years even if the customer moves to a new location.

There are no financial incentives for net metering in Sri Lanka. For residential high-end customers considering solar PV, the economics of electricity prices and decreasing equipment costs are considered to be sufficient incentive. For other customer categories with lower or subsidized electricity prices, net metering may not be economically viable at present. The sustainable energy authority makes available an Excel tool to help prospective net metering customers assess the commercial viability of the investment.

Morocco (2009)

Unlike in many other countries, in Morocco there seems to be an emphasis on industrial customers in the net metering policy as self-generation from installations of 10-50 MW are specifically noted and only interconnections at the medium and high voltage levels are monitored. The net metering framework does not therefore apply directly to small generators up to 20 kW as they are not required to provide information to the regulator although some nevertheless may be participating. In terms of customer compensation, any surplus electricity can be sold to the utility at a negotiable price, which is around 60% of the medium voltage utility retail sale price, less a fixed fee of approximately EUR 0.07/kWh (USD 0.092 or KES 7.97) for use of the grid. Although it has been reported that most Moroccan households already use electricity meters suitable for net metering, the lack of a clear regulatory framework for smaller systems and the low tariff offered are seen as barriers to wider adoption.

Uruguay (2010)

Uruguay allows a maximum system size up to 150 kW under net metering. The Uruguayan scheme does not have provisions for carry forward of excess credits but instead applies a “net billing” approach where surplus generation is purchased by the state-owned utility at a



24

tariff established in the contract between the two parties. The cost of installing the net meter is borne by the generator but the utility is responsible for installation. Uruguayan general investment incentives such as tax breaks may be applicable to net metering systems, including a specific provision for income tax exemption for up to 12 years for solar power generation.

Jamaica (2011)

Jamaica has a net metering policy that entered into force in May 2012 under which residential systems up to 10 kW AC net output and commercial up to 100 kW AC net output are eligible. A net metering tariff is in place that is based on the avoided cost of generation plus a modest premium so as not to overly compensate customers thereby avoiding impacts on the utility or other ratepayers. When a net metering application is approved, the customer receives an automatic licence for generation and supply.

South Africa (2011)

South Africa is the only example among the countries surveyed where non-renewable energy sources are also eligible under net metering. Similar to the USA and Canada with state- and province-level implementation, net metering in South Africa is implemented at the municipal level, guided by national standards with a maximum system cap of 100 kW. In addition to maximum individual system limits, the national utility (Eskom) may apply embedded generation limits as a percentage of either (a) the transformer rating or (b) the feeder peak load. The diagram on the next page indicates the limits applied.27

In Cape Town, which is the municipality where net metering is most advanced, the city has a specific net metering tariff for both residential and small commercial. The tariff structure is interesting in that a new fixed service charge is applied to residential customers and an energy charge is levied on each kWh exported to the grid. On the other hand, the retail electricity (consumption) tariff is reduced. For small commercial net metering customers, the consumption tariff remains the same but the normal fixed service charge is waived. Small commercial also pay an energy charge on kWh exported. This structure was implemented to ensure the municipal utility recovers its fixed costs.

27 MacColl, Barry. 29 August 2012. Eskom. Embedded PV Generation – Considerations (presentation at Solar Power Africa). Noted “EG” is Embedded Generation and NMD is Notified Maximum Demand.



25

Figure 3 Solar PV individual generator size limits applied by Eskom

Brazil (2012)

The recently-adopted Brazilian net metering policy sets the maximum individual system size at 1 MW for commercial and industrial customers and 10 kW for residential. A time-of-use tariff is in force and exported units are compensated for only with consumption at the same rate. Net metering surplus credits can be carried forward for a period of up to 36 months after which they are forfeited. Customers can transfer any energy credits to other organizational units fully or partially owned by them, a design feature specifically introduced to enable community installations to share credits and can be considered a form of “multi-site banking”. In Brazil customers benefiting from subsidized tariff rates cannot participate in net metering. In order to facilitate the uptake of net metering, the cost of any expansion or increases in the distribution system exclusively due to the connection of micro-and mini-generators are fully borne by the distributor.

4.4 Key lessons learned

This subsection provides information on what other countries have been able to achieve in terms of distributed renewable energy under net metering and any challenges or issues that have arisen. This is presented for countries where information is available – for many there was no data. Examples of



26

the contribution of net metering to economic development in selected countries are noted in Volume 2.

As of December 2012, a reported 302,380 net-metered systems were installed in the United States. More than 61,400 grid-connected PV installations were completed in 2011 and 89,620 in 2012 under net metering, a respective annual growth rate of 30% and 46%. Of these, 88% were residential systems in 2011 as opposed to 24% in 2010. This led to a 2011 total of nearly 220,000 solar PV installations connected to the US grid, of which 188,000 were residential installations.

In terms of capacity, by the end of 2011 distributed solar PV reached a total of 2,400 MW installed. Roughly two-thirds of this as of January 2012 is installed by commercial customers with many system sizes over 100 kW, albeit not all under net metering. The 89,620 new net metering customers connected in 2012 resulted in 1,151 MW installed, bringing the national cumulative total to over 3,500 MW. This compares with 200 MW of grid-connected solar capacity in the US in 2005 before the Energy Policy Act was passed.

Generally states with higher individual system limits (> 1 MW) have seen the most uptake of net metering, leading to about 80% of the installed capacity being concentrated in five states – California, New Jersey, Arizona, Hawaii and Massachusetts. State subsidies for net metering or distributed generation where available have also played an important role.

In California if not elsewhere in the US, distributed generation much of which is under net metering, is taken into account in the need for generation capacity. Utility long-term resource planning includes customer-sited generation based on load forecasts that include historic and anticipated customer generation. As a specific example in June 2009 the California Energy Commission denied an application to build the 100 MW natural gas fired Chula Vista peaking plant with some recognition that significant solar distributed generation could be a viable alternative.

In Denmark, since June 2010, 61,687 private “micro” (apparently up to 6 kW) solar PV systems have been installed with a total capacity of 333 MW (2.5% of installed capacity or 5% of peak load) as of December 2012. In January 2013 this figure was revised upwards to 68,900 installations and 377.5 MW, and may have reached 400 MW across 80,000 installations (average 5 kW per installation) by February 2013 according to Danish power system operator Energinet.dk. This compares with approximately 15 MW of solar PV capacity in the 1998-2010 period and well exceeds Denmark’s target of 200 MW solar V by 2020.The significant uptake is due to the incentive schemes available and a decrease in module prices. The greater-than-expected uptake in solar PV under net metering is causing Denmark to consider if its incentive schemes – in combination with decreasing equipment prices – have been too generous, and some of these will likely be revised in the future.

In addition, as of 2011 approximately 400 small-scale (< 50 kW) wind turbines have been installed, the majority at the residential level. Under net metering with settlement, Denmark has also supported the establishment of district-level combined heat and power plants (solar, biomass, fossil-fuel) for local electricity supply, with strong success. Many of these are cooperatively or collectively owned.

Thailand before switching from net metering to a FIT programme for small-scale renewables had 16.9 MW installed as of September 2006 across 97 residential, commercial and industrial customers, being 66 kWp of solar PV, 9.1 MW of biogas, 3.2 MW of rice paddy husk, 400 kW of wood residue, 3 MW of palm oil residue and 1 MW of rice straw residue.



27

From policy inception in Tunisia in 2004 until 2008 no information on net metering uptake is available and it is assumed to have been minimal due to fairly low electricity prices and possibly some uncertainty in the legal framework and the utility’s intentions. However, from 2009 when a subsidy scheme (Prosol ELEC) for residential solar PV systems up to 5 kWp was introduced, 739 net-metered systems representing 1.3 MWp were installed as at February 2013 against 1,400 customer requests totalling 2.4 MWp. This has brought Tunisia close to achieving its initial target of 1.5 MW from approximately 1,000 residential (including apartments) systems by 2011 and is a contribution towards the medium-term goal of 15 MWp from solar PV alone.

In Sri Lanka, a country with no specific incentives for net metering but high electricity prices, from policy inception in 2009, 700 kW of net metering have been installed as of June 2013 in aggregate across approximately 300 customers. The average system size is 2 – 4.5 kW, almost all of which are solar PV. No adverse impacts have been experienced so far and the net metering programme has thus been expanded to allow system sizes of up to 10 MW.

By comparison, as of March 2013 Sri Lanka had achieved 331 MW of operational small-scale (< 10 MW) renewable IPPs (biomass, hydro, wind) under its Feed-in-Tariff, contributing 730 GWh or 6.3% of Sri Lanka’s electricity generation in 2012. A further 259 MW are contracted. The Feed-in-Tariff was first instituted on an avoided cost basis in 1996 and switched to a cost-reflective tariff in 2007. About 25% of the FIT projects received concessional finance.

In the unlikely scenario that all high-end domestic customers in Sri Lanka were to adopt net metering, utility revenue loss of USD 168 million/year is projected against cost savings on future generation of USD 85 million/year. A further potential future challenge has been noted in that there is a USD 0.03 kWh differential between daytime marginal electricity costs when net metered solar PV exports to the grid versus peak evening consumption – similar to the Kenyan situation. In a high-uptake scenario where the utility would be compensated for this in addition to possible “banking” charges, the attractiveness of net metering for customers would likely decrease significantly.

South Africa is still in the early stages of implementing a net metering policy with at least three municipalities participating (Cape Town, Nelson Mandela Bay) or considering (eThekwini Municipality) a scheme. In Cape Town, three residential and small commercial pilot net metering projects are operational, one being a rooftop 3.8 kWp solar PV system initiated in February 2011. In Nelson Mandela Bay Municipality a domestic pilot with 5 kWp solar PV, 1 kW wind and a 1050Ah @ 48V battery bank is in place. Part of the pilot is to test how storage may or may not play a role in net-metered systems. A commercial-sized system is also in place.

In Morocco, information on uptake was not available but it is noted that one grid-connected 70kWp solar PV system installed on Terminal 2 of Casablanca airport is operational and has had no impact on grid operations.



28

5 The potential market for net metering in Kenya

The section assesses the likely maximum uptake of net metering including technology types, number of potential net metering customers per tariff category, typical installation size, typical installation generation, amount available for grid supply, aggregate capacity and aggregate generation.

5.1 Eligible RE technologies

Most of the discussion in this report refers to net metering for solar PV but other small-scale renewable energy technologies will be considered in the analysis and could be eligible for net metering.

Solar

Net metering could in principle apply to all type of distributed RE generation. The demand for net metering is expected to come mostly from solar PV for several reasons, such as:

High electricity price in Kenya, higher than the levelised cost of solar PV electricity.

PV systems can be sized to precisely meet the energy needs of the facility. This allows for flexibility and modularity. However, high instant variability of solar PV generation depending on cloud coverage requires an installed capacity higher than the demand, thus creating volatile instant excess power generation that can benefit from a net metering arrangement.

Proven resources. Solar resource information is widely available and for small scale installations no thorough resource assessment is needed. Other RES are site specific (wind, hydro, bioenergy). For the case of wind energy, no comprehensive wind data information is available.

Flexibility/modularity. Future expansions of PV systems are simple. The possibility to mount arrays on roofs makes it particularly appropriate where land is scarce.

Rapid installation and low maintenance costs. O&M is invariably higher for RE technologies with moving parts such as wind, hydro and bioenergy.

In Kenya, the small, micro, and pico solar PV market is more developed than the market for other RE technologies of the same size, e.g. wind. Customer familiarity, choice and confidence in equipment, service providers and pricing, facilitates quicker deployment of systems and more rapid market development.

Compared to solar PV, bioenergy projects (such as biogas or biofuels) and small and mini hydro are typically larger in scale and can benefit from the existing FiT scheme, e.g. KTDA’s 900 kW Imenti small hydro project.



29

Other technologies

While this study is focused on solar PV, Kenya does already have some examples of net metering candidates using other technologies, albeit not in the residential sector:

The Kilifi Plantations 150 kW biogas system on the coast was designed with grid integration in mind but due to lack of such arrangement the two 75 kW generators (one normal / one back up) have been scaled back to operate at 50 kW (removal of turbo compressor) for a demand of 60 kW. With the existing waste, the power output could be increased from 50 kW to 120 kW but would induce a power export of 60 kW.

A municipal irrigation project at Embu south of Mt Kenya that has a 58 kW micro-hydro facility installed but currently dissipates any surplus power in heat sinks, again due to no opportunity to supply the grid. In both these cases neither the customer nor other users are benefiting from the surplus power available.

The 920 kW KTDA Imenti small hydro project (1 MW turbine, 920 kW capacity, average of 600 kW for own consumption and 300 kW for export, but with a peak demand of up to 1.3 MW) that sells surplus electricity under a PPA may have been better placed as a net metering project.

5.2 Solar PV costs and cost projections

The rapid cost decrease of solar PV is one more reason why net metering customers would opt for this technology. In determining financial attractiveness of solar PV versus electricity tariffs it is fundamental to establish current installation costs and price projections.

PV system costs have decreased dramatically over the past two decades. In recent years they decreased at a rate of 18% p.a. Based on recent projects in Kenya as well as international literature (IRENA 2012, NREL 2012), the current (2013) capital cost of grid-connected PV systems (with no battery storage) can be estimated at 2.50 USD/Wp. This investment figure can vary by plus or minus approximately 0.30 USD/Wp, depending on the size of the installation. That means systems that are around 1MWp in size can have an investment cost of 2.20 USD/Wp, while smaller residential systems below 10 kWp will cost about 2.80 USD/Wp.

An approximate cost split can be found in Figure 4 . Solar modules represent half or less of the total investment cost.



30

Figure 4 Investment cost split for grid-connected PV systems

Table 3 provides further details of the breakdown between the main solar PV project cost components. The SOS Mombasa pilot project cost distribution is known and this value has been extrapolated to the other projects. The example systems are based on what is expected to be a “typical” project size in the customer categories presented. It should be noted that larger systems in the range of 500 kWp and above may have a different cost structure depending on the specific project circumstances such as interconnection requirements.

Table 3 Kenya solar PV system cost breakdown by component (USD)

Project SOS Mombasa (2011)

Uhuru Flowers (2013)

Example projects (2013 prices)

Customer category28

SC CI1 DC <1500 SC CI1

System size (kWp) 60.8 72.0

5.7 58.8 364.5

Currency

USD USD % USD USD USD

Solar modules 2,680 1,251 50% 1,417 1,289 1,095

Inverters

462 462 19% 523 476 404

Other material 442 442 18% 501 455 387

Installation 335 335 13% 380 345 293

Total/kWp 3,919 2,490

2,821 2,565 2,180

Total system cost 238,432 179,280

16,103 150,779 794,570

Following years of solar PV module oversupply and unsustainable, often artificially low pricing, 2013 is expected to be the year that the global solar PV market begins to stabilize. PV module prices and installation costs will continue to decline but at a much more conservative range of 2% to 8% per

28 A description of the different Kenyan customer categories and current retail tariff structures is provided for reference in Volume 2.



31

year from 2013 to 2020, compared to the drastic price declines in previous years. By 2020, solar PV systems installed costs are expected to be in the range of 1.80 USD/Wp to 2.40 USD/Wp according to a 2012 IRENA study. Projections from other reports such as a 2012 paper by McKinsey & Company show the possibility of more dramatic reductions leading to commercial-scale rooftop system costs of approximately 1.40 USD/Wp by 202029. The higher future cost estimates are applied in this assessment for conservativeness to account for other factors that might influence prices in Kenya such as import and other taxes, material and transport costs, market size, protection and interconnection equipment and other costs.

Figure 5 presents cost projections from the IEA and Solarbuzz (IRENA 2012) as well as current well as the cost curves used in this study. Prices are assumed to continue dropping at a conservative rate of 2.5% p.a.

Figure 5 PV cost projections 2013 - 2030

5.3 Current situation in Kenya

The market for small-scale grid-connected solar PV in Kenya is just coming into existence. Solar PV has traditionally been an off-grid technology, with the exception of solar energy power back-up systems in the residential/ small commercial sector (a market estimated well below 1 MWp p.a.). Recent investments in the grid-connected environment predict an upward trend in the market. Table 4 presents an example of grid-connected solar PV projects in Kenya that could potentially benefit from a net metering policy.

29 Rrister Aanesen et al (May 2012) Solar Power: Darkest Before Dawn, McKinsey & Company, p. 4.

IEA Res./Comm.

IEA Res./Comm.

IEA Utility scale

IEA Utility scale

Solarbuzz

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

2010 2015 2020 2025 2030

PV

in

sta

lle

d p

rice

US

D/k

Wp

Residential (=< 10 kWp)

Commercial (10 - 1000kWp)



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Table 4 Small scale grid-connected PV projects in Kenya

Project Size (kW) Year Installed Source of funds/ rationale of investment

UNEP Nairobi 515 2011 Donor funded (grant). Primarily demonstration value. Based on size, the project is eligible for FiT.

SOS Children’s Village Mombasa

60 2011 Donor funded (grant). Primary objective was to reduce operating expenses for the facility.

Uhuru Flowers 72 2013 Privately funded, commercial venture.

Strathmore University 500 Planned for 2014

Donor funded (concessional loan). Based on size, the project is eligible for FiT.

Interest has recently sparked in the commercial and industrial sectors as solar PV is seen as a potential to (at least partially) offset grid electricity costs and reduce overall operating expenditure. The Kenya Association of Manufacturers Regional Technical Assistance Program (KAM/RTAP) financing facility pipeline currently has a total of 22 solar PV grid connected projects totalling 16 MWp (i.e. 730 kWp per project in average), notably 3 large projects of 3 MWp capacity each. These projects could be candidates for net metering but while the policy is not available, those with a size eligible for FiT are opting to consume power directly and export “spillage” under the FiT framework. Most of these solar energy systems are sized based on base load demand in order to minimize exports.

Examples of solar PV projects under development include flower farms, tea factories, shopping malls and even large industrial consumers. Tyre maker Sameer Africa and Bamburi Cement are for example seeking cheaper and more reliable sources of energy and are analysing the feasibility of solar power among other technologies.

Up to now all requests for net metering systems are from larger electricity consumers, normally for a minimum capacity of 50 kW up to a few MW. There is not much interest from the residential sector. Some reasons to explain this could be:

Preference among homeowners for inverters with battery storage providing 8 hours autonomy for priority loads sufficient for the frequency and extent of power cuts.

High costs per kW for smaller PV systems; levelised cost per kWh for PV systems increases to unaffordable levels if all power output cannot be monetized.

Lack of an appropriate regulatory framework enabling compensation for any spill over of electricity from solar PV systems

Lack of awareness among customers of the concept of net metering

Unlike industrial and commercial consumers, the typical load profile in the residential sector would show peaks of consumption early in the morning and late afternoon/evening. This reduces the potential of consuming solar energy directly and makes the systems fully reliant on net metering in order to be financially attractive.

The residential sector could according to experts also become a promising market if net metering is made available. Large real estate developments, the possibility of financing the energy systems through mortgages and other mechanisms such as leasing arrangement or microfinance institutions



33

could facilitate the penetration of solar energy systems in the residential sector. Experience from other countries shows that if the net metering export tariff is sufficient or the displaced retail tariff is high enough and regulatory framework provides certainty, the domestic sector will start to adopt net metering without any other incentives, albeit slowly.

5.4 Demand assessment in Kenya

In determining the size of the market for net metering, it is important to understand reasons for investment:

Financially attractive investment: This includes cutting operating expenditure and hedging against increasing electricity prices (e.g. Uhuru flowers farm, SOS, Strathmore)

Environmental reasons: green image, meeting environmental objectives, demonstration value. Most donor driven projects fall into this category (e.g. UNEP, SOS)

Independence from the grid/reliability of supply: Grid-connected solar energy systems without batteries do not increase reliability of supply; they cannot function as back-up systems. Consumers investing in battery back-ups will charge batteries from the grid; they may consider incremental investment in solar PV arrays on a cost/benefit basis. Net metering would enable to increase the capacity of PV systems.

Project developers tend to compare the Levelised Cost of Energy (LCOE) of grid connected solar PV to the current cost of electricity from Kenya Power (15 to 25 USDc/kWh depending on consumer category and consumption patterns as shown in section 6 below and further presented in Volume 2).

Table 5 Solar PV LCOE for 2013 & 2018 and input assumptions

Customer category DC

<1500 DC

>1500 SC CI1 CI2

System size kWp 5.7 18.8 58.8 364.5 2525.1

Capacity factor % 20% 20% 20% 20% 20%

Generation (year 1) kWh 10,000 32,947 102,999 638,561 4,423,899

System degradation factor %/year 0.50% 0.50% 0.50% 0.50% 0.50%

Capital costs USD/kWp 2,821 2,821 2,565 2,180 2,180

Total capital costs USD 16,103 53,055 150,779 794,570 5,504,718

O&M costs % of CAPEX 0.50% 0.50% 0.40% 0.30% 0.30%

Annual O&M costs/kWp USD/kWp 14 14 10 7 7

Total annual O&M USD 81 265 603 2,384 16,514

Equipment replacement (year 10) % of CAPEX 20% 20% 20% 20% 20%

Equipment replacement cost USD 3,221 10,611 30,156 158,914 1,100,944

Discount rate % 10% 10% 10% 10% 10%

Project lifetime Years 20 20 20 20 20

LCOE 2013 USD/kWh 0.1996 0.1996 0.1799 0.1517 0.1517

Capital cost reduction factor %/year 2.50 2.50 2.50 2.50 2.50

LCOE 2018 USD/kWh 0.1759 0.1759 0.1585 0.1336 0.1336



34

The calculated LCOE of solar PV in Kenya for 2013 and 2018 is presented for different system sizes based on the input assumptions in Table 5, above.

The 2013 and 2018 LCOE for solar PV in Table 5 falls broadly in line with that of the literature, such as the range of USD 0.17 – 0.53/kWh for Africa for 2010-2012 as per IRENA’s cost database30 and the 2012 values of USD 0.20 – 0.51/kWh for Africa and USD 0.20 – 0.35/kWh for “six developing countries” against a first quarter 2012 global average of USD 0.11 – 0.25/kWh as reported in Bazilian et al31. In mid-2012, the Fraunhofer Institut for Solar Energy Systems found an average LCOE of EUR 0.15/kWh and 0.13/kWh respectively for small, roof-mounted and large, ground-mounted solar PV installations in Germany, with slightly lower costs for the same in Spain due to the higher average solar tilted irradiation more comparable with areas of Kenya at 2,000 kWh/m²/year32.

Interest in net-metered systems is closely linked to current electricity tariffs but the following need to be considered for a proper assessment:

Relevant electricity tariff components, i.e. components than can be offset with self-generation: fixed charges will continue to be paid and typically, a net metering solar facility has minimal impact on the demand component of the demand-metered customer’s bill.

Perception of tariff escalation: electricity grid costs have been dramatically increasing over the recent years. Electricity costs combine tariff and pass through costs such as fuel surcharge. With planned RE power generation investments (e.g. geothermal and imports from Ethiopia), expected to reduce the use of fossil fuel and eradicate the fuel surcharge, high investments required in T&D infrastructure should keep the cost of electricity high (see Volume 2 for information on tariff projections).

Solar PV cost projections: the projection of solar PV prices explained in section 5.2 above has been used to predict cash flows and energy production expected from solar PV systems.

One important input parameter in Table 5 is the energy yield of the solar PV system that is determined by a number of factors, of which the first is solar irradiation as received on a flat or inclined plane. In Kenya this can vary substantially depending on location as shown in Figure 6.

30 IRENA (2013) Renewable Power Generation Costs in 2012: An Overview, p. 57

31 Morgan Bazilian et al (2012) Re-considering the Economics of Photovoltaic Power, p. 8

32 Christoph Kost et al (2012) Levelized Cost of Electricity: Renewable Energies, 20 May 2012 edition, Fraunhofer Institut for Solar Energy Systems (ISE) study, p. 3



35

Figure 6 Average daily solar radiation at 15 stations in Kenya from 1964-199333

33 LCPDP, p. 93.

93

The average daily radiation in more than 28,000km2 of land in Kenya is above 6 kWh/m²*d throughout the year, thus resulting in a continuously good and relatively stable potential for electricity generation from solar.

Figure 25: Average Daily Radiation Measured at 15 Meteorological Stations in Kenya by Month of Year in the Period 1964-1993

Average daily radiation

0

1

2

3

4

5

6

7

8

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Month

[kW

h/m

²day

]

Mombasa Airport

Malindi

Lamu

Nairobi Kenyatta

Nairobi/ Dagoretti

Muguga

Narok

Garissa

Nakuru

Kisumu

Nanyuki

Eldoret

Kitale

Lodw ar

Mandera

Solar Technical Characteristics Solar technologies for generating electricity are of two general types:

i) Photovoltaic (PV) ii) Solar thermal electricity conversion (STEC)

Photovoltaic (PV) technology Photovoltaic technology uses solid-state semiconductor devices to convert sunlight into direct current electricity as shown in figure 25. Although the underlying science was discovered by Becquerel in the nineteenth century, significant progress in commercialization became possible with Bell Labs’ invention of the silicon solar cell in 1954 and its early use in powering earth satellites.



36

Solar irradiation adjusted by efficiency of conversion and any losses results in energy yield values in kWh per kW installed. The difference in potential is clear with the example of a 1 kW solar PV in Kirinyaga at the south of Mt Kenya that would generate about 1,500 kWh per year, whereas the same system installed at Lodwar in the north could generate more than 2,200 kWh over the same period34. This is also known as the system “capacity factor” and is presented as a percentage of actual versus theoretical maximum output. The capacity factor influences project economics since the same cost inputs may deliver more or less electricity production.

Including losses and system downtime, after conversion to AC output the three Kenyan net metering pilot projects have capacity factors of:

19.8% (Uhuru Flowers, Timau);

16.9% (UNEP, Nairobi); and,

15.5% (SOS Children’s Village, Mombasa).

However, for this assessment a uniform capacity factor of 20% is applied. This may result in overly optimistic project performance in areas of lower solar irradiation. Nevertheless, as one key task in this study is to assess the impact of reduced electricity sales due to net metering on utility and government revenue, a 20% capacity factor gives a maximum “worst case” scenario in order to be conservative.

Furthermore, it should be noted that the calculation methodology and derivation of rate of return that follows assume that all projects/systems are 100% equity financed. Project Internal Rate of Return (IRR) is therefore indicated. This is for the purposes of comparison of fundamental project performance across different sizes and consumer categories. In reality certain projects especially those of a larger size or implemented by corporate entities may secure bank financing and the debt/equity ratio would influence the investor’s rate of return, along with taxes and other parameters that have been excluded in this assessment.

Figure 7 below presents a cash flow analysis for a hypothetical 365 kWp solar PV system offsetting CI1 customer category electricity tariffs. The result is a project IRR of 14%. The main assumptions we make in this analysis are:

Customer energy consumption: 640 MWh/a (average of CI1 category). 67% of energy produced by the system assumed to be consumed directly. The remaining 33% is exported to the grid against an equivalent energy credit.

System output: as per Table 5 a capacity factor of 20% and system degradation of 0.5% per year. 365 kWp is the system size required to self-generate 100% of energy demand during daylight hours.

Costs: capital investment of 2180 USD/kWp (2013), O&M expenses estimated at 0.5% of CAPEX per year, 20% of CAPEX in reinvestment (replacement of parts) at year 10, a 10% discount rate and a 20-year project lifetime as per Table 5.

Electricity tariff projections: according to Volume 2 of this report.

34 Ministry of Energy Kenya and Ministry of Foreign Affairs Finland (Nov 2008), Updating the Rural Electrification Master Plan, Final Report under the MFA Contract – Provisional Master Plan – Volume 3: Background and Technical Studies, Annex 3.2.1: Assessment of Renewable Energy Options, p. 9.



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Figure 7 Cash flow analysis for 365 kWp system offsetting electricity of CI1 consumer

This net metering project under a net metering framework where all electricity exported to the grid is credited at an equivalent amount gives a 14% rate of return. However, if the electricity exported to the grid is credited at a lower rate than retail tariffs, returns would decrease. Three scenarios have been modelled for net metering rates:

Scenario 1: net metering credits = Retail tariff

Scenario 2: net metering credits = FiT

Scenario 3: net metering credits = zero.

These scenarios are also illustrated in in Figure 8 below.

Figure 8 Scenarios for net metering exported electricity rates

Table 6 below. Results are shown for investments made in both 2013 and 2018:



38

2013: current solar PV investment costs and current tariffs

2018: lower solar PV investment costs and higher tariffs, which should result in a more favourable environment for net metering.

Table 6 Expected returns (IRR) of solar PV net metering systems

DC <1500 DC >1500 SC CI1 CI2 CI3 CI4 CI5

2013

NEM 11.5% 24.9% 15.0% 14.0% 11.8% 11.0% 10.5% 10.3%

FiT 8.5% 17.7% 11.3% 11.5% 10.0% 9.4% 9.0% 8.9%

0 tariff 4.5% 14.0% 7.1% 6.5% 4.8% 4.1% 3.8% 3.6%

2018

NEM 16.1% 34.1% 20.6% 19.4% 16.4% 15.1% 14.5% 14.2%

FiT 12.1% 23.7% 15.6% 15.7% 13.7% 12.8% 12.4% 12.2%

0 tariff 7.6% 19.2% 10.7% 10.0% 7.9% 6.9% 6.5% 6.3%

Based on the results of

Table 6, it can be concluded that net metering systems are more financially attractive to consumers in categories DC (above 1500 kWh/month), SC and CI1 if an adequate financing structure can resolve the negative cash flow over the first 7 years of the project. Uptake of solar PV in other consumer categories should be limited but there may be specific cases where another renewable energy resource is available to the customer that could result in a more attractive IRR especially for a larger-sized commercial project.

It is important to stress that the rates of return shown in

Table 6 are calculated under the assumption that two thirds (67%) of the electricity generated by net metering customers is consumed directly, and is thus offsetting the complete retail tariffs, while the remaining third is exported to the grid in exchange for net metering credits compensated at the rate outlined in the three scenarios.

Certain large projects such as the 515 kWp system at UNEP (CI2 category) have low returns but have motivations other than financial performance, such as environmental and demonstration purposes. The share of these types of projects is expected to be high initially, but in the medium to long term most projects are expected to be motivated primarily by financial performance.

5.5 Estimation of market size

The previous section gives an indication of what type of energy consumers would be more inclined to invest in net metering systems. In order to estimate the overall size of the market for net metering, uptake references from other markets are used.

While net metering laws now exist in at least 40 countries (as discussed in Section 4), most of these have only adopted net metering recently and there is not much information regarding uptake. For determination of uptake figures comparison with countries with other policies favouring adoption of grid connected solar PV (such as FiT) is also relevant. Table 7 presents uptake information from



39

countries/states that have adopted net metering such as Sri Lanka, California and Tunisia, or other incentives such as FiT in Israel.

Table 7 Net metering uptake in other countries

Case study

Policy Electricity tariffs and insolation

Uptake figures Other relevant program features

Sri Lanka Net metering since 2009

Tariffs are comparable to Kenya ranging from 15 to 35 USDc/kWh depending on level of consumption. Insolation is lower, ranging from 4.2 to 5.6 kWh/m2/day.

300 installations after three years of commencement (~0.01% of customers) and totalling 0.7 MWp (negligible solar PV NEM capacity in comparison to country’s total installed capacity of 3091 MW).

System size limited to contract demand or 10MW.

There is also a FiT in place for wind, bioenergy and hydro.

California Net metering since 1996

Electricity tariffs are lower than in Kenya at 17.5, 17.0 and 12.3 USDc/kWh for residential, commercial and industrial consumers respectively. Insolation in California is high.

There are over 120,000 residential and non-residential systems enrolled in California's NEM program. In 2010 total capacity was of 1,022 MWp. This equates to 1.4% of California’s total installed capacity or 1.7% of the electricity peak demand.

Individual systems eligible for NEM are capped at 1 MW.

NEM is also capped at 5% of aggregate non-coincident peak demand.

Israel FiT for solar PV approved in 2008

Generous FiT of 43 USDc/kWh (> 50 kWp) and 54 USDc/kWh (< 50 kWp). Insolation in Israel is comparable to Kenya at 5.5 kWh/m2/day.

250 MWp of solar PV. This equates to about 2.1% of installed capacity and almost 1% of total energy production.

The tariff is capped to 50 MW for systems under 50kWp and 300MW for systems above 50 kWp. Individual system restrictions apply: 15 kWp for residential, 50kWp for commercial and 5MW for utility scale)

Tunisia Net metering in 2004

Electricity prices are low, between 10 and 13 USDc/kWh

739 residential consumers with an average system size of 1-2 kWp. Installed capacity estimated at 1.3MWp, negligible in comparison to the 4000 MW of installed capacity in the country.

Since 2009, net metered solar PV receives a subsidy capped at 5 kW. The expectation is to reach 1,000 homes and an installed capacity of 1.5 MW in phase I.

The only country having adopted net metering that closely compares with Kenya is Sri Lanka, which makes giving an accurate projection for uptake of net metering a challenging task. It is however possible to estimate an upper limit for uptake based on more developed markets such as California or markets with more attractive incentives such as Israel.

Considering the cases of California or Israel as a measure of the maximum uptake in Kenya, in the medium term, and depending on favourable policy a maximum of 2-3% of peak demand could come from net metering systems. Based on the peak load forecast of the LCPDP of 3,751 MW by 2018, the potential net metering market can be estimated at a maximum of 100 MWp of solar PV with negligible contribution from other technology types by 2018. In is notable that the maximum potential uptake is in line with the draft National Energy Policy 2018 target of 100 MWp from solar.



40

The actual uptake is expected to be lower, based on the Sri Lankan experience of less than 1 MW in 3.5 years.

Figure 9 Projected maximum installed capacity for net metering solar PV

The market for solar PV is estimated to grow rapidly in case a favourable net metering policy is in place. Based on an estimated 8 MWp of projects in 2013 (50% of the capacity currently in the RTAP pipeline, see section 5.3) and a 100 MWp installed capacity forecasted for 2018, the growth rate results in 65% p.a. This is significantly higher than the growth rate for total installed capacity of 21% p.a. between 2013 and 2018 according to LCPDP of 2011.

5.6 Typical installation size

Based on the previous sections, uptake of solar net metering systems can be estimated for the different consumer categories as shown in Table 8 below. The highest demand (in terms of installed capacity) is to be expected from consumers in the SC and CI1 categories (based on the projected project IRRs). Nevertheless, a few MW-size projects in the C13- C15 categories including those deploying other technology could have an important impact on these forecasts. The total maximum number of solar PV projects is estimated at 16,000 by 2018.



41

Table 8 Maximum uptake of solar net metering per category

Customer category

Nr of customers

Avg energy per customer (kWh/a)

Avg solar PV system size (kWp)

Uptake (%)

Uptake capacity (MWp)

NEM share

Nr of NEM projects

DC 1,656,586 1,127 0.6

0-50 903,581 219 0.1 0.0% 0.0 0% 0

50-1500 749,213 2,062 1.2 1.0% 8.8 9% 7,492

>1500 3,792 32,947 18.8 8.0% 5.7 6% 303

SC 200,616 6,098 3.5 4.0% 27.9 28% 8,025

CI1 2,775 638,561 364.5 4.0% 40.5 40% 111

CI2 305 4,423,899 2,525.1 2.0% 15.4 15% 6

CI3 31 10,210,317 5,827.8 1.0% 1.8 2% 0

CI4 21 22,743,016 12,981.2 0.0% 0.0 0% 0

CI5 24 8,940,157 5,102.8 0.0% 0.0 0% 0

Totals 100.1 100% 15,938

*Information on number of customers and average energy consumption per category from COSS 2013

Not included in this assessment is the number of existing off-grid or grid-proximate users with solar PV systems that may opt to participate in net metering when the grid reaches their location. These could number in the thousands and would mostly fall in the DC 0-50 category when connected.


Lessons learned from existing PV projects in Kenya

42

6 Lessons learned from existing PV projects in Kenya

In this section we analyse three PV projects for which data is available: SOS Children’s Village Mombasa, UNEP Nairobi and a Timau (Mt Kenya) flower farm. We present relevant considerations from this data, including supply profile, demand profile, system performance, system downtime, reason for downtime, payback period, changes in KPLC power bills, etc. We also draw lessons for future net metering in Kenya.

6.1 Case study 1: SOS Children’s Village

60 kWp solar energy system at SOS Mombasa

Project: SOS Children’s Village Location: Mombasa, Kenya Date installed: early 2011 Capacity: 60.84 kWp Other specs: Centrosolar PV modules, SMA inverters Investment: 178 kEUR (238 kUSD) Investor: SOS Children’s Village (charity) Expected output: 98.8 MWh/a (92% conversion efficiency) Actual output: 83 MWh/a (estimated, 2012) Solar PV contribution: 52% of total energy demand Direct consumption: 65% of PV output

The solar PV system at SOS Children’s Village has a capacity 60.84 kWp. It was installed with the purpose of reducing operating expenses for the facility and the project was funded by donors. This solar PV system is considered to be the first grid interactive system in Kenya.

The system was sized to cover practically the entire electricity demand of the facility. About two thirds of the energy produced by the solar PV system is consumed directly and the other third exported to the grid. The system was conceived to operate under a net metering framework but the lack of such framework up to date determines that the facility does not receive compensation for the electricity exported to the grid. Kenya Power however keeps accurate records of the electricity the system has injected into the grid. These figures are analysed in the following section.

System output/performance

The system was designed to provide 98,800 kWh/year (AC, after conversion with efficiency of 92%). Based on information obtained from SMA’s sunny webportal35 the system generated about 83,000 kWh in 2012. The difference in output can be attributed to system losses and maintenance issues

35 SMA online information system. Information is obtained from the SMA inverters on site through the mobile phone network. The annual energy production figure provided is only an estimation based on the days for which accurate information is available. Due to communication problems between the inverters and the information system, accurate output data is only available for 205 days of 2012.



43

(some broken modules and a temporary failure in one of the inverters) as well as lack of accurate insolation data in the location which might have led to overly optimistic output estimates.

Additionally, grid failures (blackouts) prevent the solar energy system from functioning (impede synchronization of inverters) and reduce the previous output figure even further. Based on meter readings from Kenya Power, power cuts have been calculated at 214 hours in 2012, with about 168 hours occurring during daylight. This can be translated into about 4% system losses due to power cuts.

Figure 10 below provides the annual average electricity production curve for 2012 as well as the profiles for a high output day (12 March 2012) and a low output day (18 July 2012). The red curve provides the maximum output registered in 2012. This information is related to actual output registered in the SMA sunny webportal and shows that maximum power output never reaches rated peak capacity and that annual average output only just exceeds half of the rated capacity during the midday hours.

Figure 10 Measured power output from SOS PV system

In addition to the SMA portal, Kenya Power has provided metering information for the electricity imported by SOS from the grid and the electricity exported from the solar energy

system to the grid. Figure 11 shows how the total energy consumption for SOS Children’s Village in 2012 was of 159 MWh of which 34% was self-generated and 66% bought from Kenya Power. The solar energy system produced 83 MWh, of which 65% was consumed directly and the rest exported to the grid.

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Figure 11 Energy balance for SOS solar PV system

Figure 12 shows the hourly power consumption, power generation and exports to the grid for a full week in December 2012. It is an easy visualization of how the system is performing and interacting with the grid. In particular, the effects of power cuts can be noted in two occasions. Solar energy output during power cuts is interrupted.

Figure 12 Power consumption, generation and grid exports for a week in Dec 2012

Financial calculations

SOS is in the SC (small commercial) customer category of Kenya Power. Total energy bought from the grid in 2012 amounts to 103 MWh and total cost from Kenya Power bills was of 2 million KES, i.e. 19.4 KES/kWh. This cost includes several components as shown in Figure 13. In the case of direct consumption of self-generated electricity all of these cost components are offset (except for the

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fixed charge which is currently negligible). In the case of net metering transactions not all cost components might be pertinent. This discussion is however left for section 8 below.

Figure 13 SOS’ electricity charges in 2012

For the purpose of financial analysis, all cash flows and savings have been converted to USD at the rate of the initial investment in January 2011. A simple model was created to determine the financial performance of the solar energy system. The results of the model can be seen in Table 9 and Table 10. Table 9 presents the financial performance for the system if energy banking/net-metering is in place and the electricity meter runs both ways36. Table 10 presents the results for a system “spilling” the excess of energy production over consumption into the grid without compensation.

The most important assumption in this model is the electricity tariff that is offset when self-generating with PV systems. The model assumes that all components of the electricity bill with the exception of fixed charge, demand charge and VAT are relevant. The model escalates the electricity tariff based at 2.7% p.a. as explained in Volume 2 of this report.

36 Practically or figuratively

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Table 9 Financial performance of SOS PV system WITH NEM

Main parameters and assumptions: Accumulated cash flows (in USD ‘000)

Investment: 238 kUSD

O&M expenses:

0.3% of capex

Replacement of parts:

Inverters in year 10

System output:

82.4 MWh/a (degradation 0.5%/a)

Offset tariff: 19c/kWh escalating to 25c/kWh

IRR: 3.1%

Table 10 Financial performance of SOS PV system WITHOUT NEM



O&M expenses:

0.3% of capex



System output: 82.4 MWh/a (degradation 0.5%/a)

Direct consumption:

65% of output


IRR: negative

The project’s returns for SOS are low at 3.1% in case of operating as a net-metered system and negative in case the 35% of solar energy injected into the grid is not compensated for. It is however important to highlight that the initial investment in this project was done in early 2011 and since then solar PV prices have dropped dramatically. The same project with current solar PV prices would result in an 8.5% IRR for the first scenario and 2.7% for the second.



47

6.2 Case study 2: UNEP

Rooftop 515kWp solar energy system at UNEP

Project: UNEP Location: Nairobi, Kenya Date installed: February 2011 Capacity: 515 kWp Other specs: Schott and Kaneka modules, SMA inverters Investment: 1.38 million USD Investor: UNEP Expected output: 760 MWh/a Actual output: 715 MWh/a Solar PV contribution: 27% of total energy demand37 Direct consumption: 86% of PV output

At the time of installation, this project became the largest roof-mounted solar PV system in Africa. As with SOS, it was considered a flagship project for grid-connected solar PV in the region. The United Nations Environment Programme (UNEP) Gigiri office block with 650 employees is also considered the first carbon-neutral building on the continent.

The 515 kWp solar power system on the roof of the UNEP headquarters in Nairobi was connected to the grid in February 2011.


Information regarding the solar energy system’s output in 2012 has been provided by system contractor Energiebau. This information has been collected from the Sunny Portal. For comparison purposes output has also been estimated based on the size of the system, insolation data for Nairobi and typical efficiency parameters for grid connected installations. The modelled annual output is 6.5% higher than actual output. The difference is mainly attributed to power cuts (grid failure) not allowing the inverters to synchronize and supply energy.

UNEP has provided electricity bills for 2012, which show energy consumption (in addition to the output of the solar energy system). Based on UNEP’s energy consumption patterns and capacity demand (see Figure 14 below), the facility can most likely consume all the solar energy system’s output directly without requiring much interaction with the grid. Spillage of the solar energy system into the grid can occur however during weekends or holidays when the UNEP offices are not in use. A net metering framework would be beneficial in these cases.

37 Contribution of 27% considers all UNEP facilities and electric bills for the Gigiri compound (common area, parking, sewage treatment plant, etc.). Considering only the UNEP new office where the solar system is mounted, the figure is 93%.



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Figure 14 Energy demand versus solar energy production at UNEP (2012)

For the purpose of this case study, it is assumed that energy from the solar energy system is consumed directly 6 days of the week and injected into the grid on the 7th day, i.e. direct energy consumption of 86%.


UNEP is billed as a CI2 customer (2nd tier commercial/industrial) of Kenya Power. This category of consumer has a basic consumption charge of 4.73 KES/kWh and includes a demand charge of 400 KES/kVA. Figure 15 summarizes all components of electricity bills for year 2012.

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Figure 15 Electricity charges to UNEP (Kenya Power electricity bills)

The results of the financial model for UNEP’s solar energy system can be seen in Table 11 and Table 12. Table 11 presents the financial performance for the system if energy banking/net-metering is in place and the electricity meter runs both ways. Table 12 presents the results for a system “spilling” the excess of energy production over consumption into the grid without compensation.


Table 11 Financial performance of UNEP’s PV system WITH NEM


Investment: 1.38 million USD

O&M expenses:

0.3% of capex



System output:

762 MWh/a (degradation 0.5%/a)

Offset tariff: 14c/kWh escalating to 18c/Kwh

IRR: 5.0%

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Table 12 Financial performance of UNEP’s PV system WITHOUT NEM

Main parameters and assumptons: Accumulated cash flows (in USD ‘000)

Investment: 1.38 million USD

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0.3% of capex



System output: 762 MWh/a (degradation 0.5%/a)

Direct consumption:

86% of output

Offset tariff: 14c/kWh escalating to 18c/Kwh

IRR: 3.1%

The UNEP project returns are extremely low regardless of whether net-metering is available or not. Some important aspects to highlight in the interpretation of these results are:

The initial investment in this project was done in early 2011 and since then solar PV prices have dropped dramatically. The same project with current solar PV prices would result in a 7.2% IRR for the first scenario and 5% for the second.

Tariff increases for the CI2 customers as proposed in the Kenya Cost of Service Study affect the demand charge (per kVA) much more than the basic consumption charge (per kWh). Given that demand charge is not easily offset by net metering, savings are less attractive for CI customers than for other customer categories, i.e. residential and small commercial.

6.3 Case study 3: Uhuru Flowers

Uhuru Flowers, 72kWp solar energy system

Project: Uhuru Flowers Location: Timau, Kenya Date installed: February 2013 Capacity: 72 kWp Other specs: SMA inverters Investment: KES 15 million (USD 177,000) Investor: Uhuru Flowers (private capital) Expected output: 125MWh/a Actual output: not enough history available Solar PV contribution: 36% of total energy demand Direct consumption: assumed to be 100%



51

Uhuru Flowers is the first solar PV grid connected project fully funded with private capital. It was installed by project developer and EPC contractor Azimuth Power (Kenya). Azimuth indicated that this project has raised significant interest from the private sector and several other flower farms---as well as tea factories and other commercial and industrial facilities---are planning investments in solar PV to (at least) partially offset their electricity costs.

Based on interviews held with Uhuru Flowers, the monthly electricity bills used to amount to KES 500,000 (USD 5,900) and the solar PV investment of KES 15 million (USD 177,000) should allow reducing that by 80%, thus achieving a return on investment of about 5 years.


Output data from SMA sunny portal has been made available. Due however to the plant having only been installed in February 2013, annual output can only be estimated. Based on existing data and insolation parameters in Timau, annual output can be estimated at 125,000 kWh/year. An example of the system’s actual output for a week in March is given in figure below (data from SMA Sunny Portal).

Figure 16 Output of solar energy system at Uhuru Flowers during one week

It is assumed that the entire output of the flower farm is consumed directly and there is no spillage into the grid excepting circumstances when the flower farm is not operational.


Electricity bills for the flower farm are not available. Based on the figures provided in the interview regarding expenditure (KES 500,000/month), it can be assumed that Uhuru Flowers is billed as a CI1 customer. Energy consumption is estimated at 29 MWh/month and average demand at 80 kVA. Based on these figures, the contribution of the solar energy system can be calculated at 36%. It is

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safe to assume that practically the entire output of the solar energy system is consumed directly, without requiring much interaction with the grid. For modelling purposes a 95% direct energy consumption is assumed.

The results of the financial model for Uhuru Flowers’ solar energy system can be seen in Table 13 and Table 14. Table 13 presents the financial performance for the system if energy banking/net-metering is in place and the electricity meter runs both ways38. Table 14 presents the results for a system “spilling” the excess of energy production over consumption into the grid without compensation.


Table 13 Financial performance of Uhuru’s PV system WITH NEM



O&M expenses:

0.3% of capex



System output:

125 MWh/a (degradation 0.5%/a)


IRR: 10.2%

38 Practically or figuratively



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Table 14 Financial performance of Uhuru’s PV system WITHOUT NEM



O&M expenses:

0.3% of capex



System output: 125 MWh/a (degradation 0.5%/a)

Direct consumption:

95% of output


IRR: 9.4%

This project having been only recently undertaken has benefitted from low solar PV technology prices which reflect in the project’s financial performance.

It is also worth highlighting how given that most of the energy produced by the solar energy system is consumed directly (95%), the impact of not benefiting from a net metering policy is minor. The availability of a net metering framework could however have impacted the project’s size. As mentioned before, the solar energy contribution of the current PV system is only 36%. If net metering were available the system could have been sized to cover 100% of the energy demand. This would imply an installation of 200 kWp.

6.4 Lessons learned

The three pilot projects presented in the previous sections allow for important conclusions regarding grid-connected PV systems and net metering.

Solar resource (insolation): specific output of solar PV systems (kWh/kWp) is 30% higher in Timau than in Mombasa, as evidenced by the pilots in each location. This is not surprising since it is in line with insolation maps. It is important to highlight that systems will be far more attractive in certain regions than in others.

Reduction of solar PV costs: investment for SOS’s system was 3,850 USD/kWp as opposed to 2,460 USD/kWp for Uhuru Flowers two years later. Both projects have similar components (SMA inverters), it can be therefore estimated that installation prices for grid connected systems have declined at 20% p.a. in Kenya in line with the drastic PV price reductions seen in the global market.

Power cuts and system output: based on metering information available for SOS and UNEP it was estimated that grid downtime has reduced the solar energy systems’ output by 4% to 6.5%. Power outages need to be considered by investors in their financial feasibility calculations. In the case Uhuru Flowers, a 5% outage rate would



54

reduce IRR from 10.2% to 9.4%, which for this particular project is the equivalent to the difference in project returns between the net metering credit and no credit scenarios.

Metering: hourly meter readings as well as separate metering for imports and exports of electricity (as available for SOS, which actually has readings every 15 minutes) provides vital information to determine how much energy is consumed directly, exported to and imported from the grid. This information is essential for the investor---in valuing the returns on investment---and for the utility to determine the impact of the solar energy project in the overall system. It is important to determine exactly what type of metering is needed for grid interactive projects, balancing the increased cost in hardware and administration with the usefulness of data provided.

Offsetting electricity tariffs: in analysing returns on investment of the different pilots, it is vital to determine which charges of the electricity bill are relevant and which are not. It is worth noting that for the SOS case (SC customer), fixed charges are negligible and most of the energy tariff could be offset with grid-connected energy systems. In the case of larger commercial/industrial consumers such as UNEP and Uhuru Flowers, fixed charges and demand charges (which can be considered invariable) are estimated at 10% of the electricity bill but proposed at 30% to 40% in the COSS 2013. This could reduce the attractiveness of net metering for large commercial/industrial consumers.

Impacts of net metering on system sizing: a net metering framework is not necessary for grid-connected RE systems generating below the consumption curve. As shown in the cases of UNEP and Uhuru Flowers, most of the energy is consumed directly without requiring much interaction with the grid. It is however important to highlight that if net metering were in place, systems would have most likely been sized differently. As mentioned before, the solar energy contribution of Uhuru Flowers’ PV system is only 36%. If net metering were available, the system could have been sized to cover 100% of the energy demand. This would imply an installation of 200kWp as opposed to 72 kWp.


The technical impact of net metering on Kenya Power

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7 The technical impact of net metering on Kenya Power

This section investigates the high-level technical impact that net metering might have on the stability of the Kenya grid, with the objective of identifying any constraints on the endorsement and uptake of net metering. We consider the size of net metering market potential (at current levels and in the future) and its impact on grid operations, both from a regional and aggregate perspective. We also consider time of supply and customer consumption.

In considering the impact of net metering uptake in Kenya we assume 100 MWp of net metering systems. As we discuss in Section 5, this is our upper estimate of possible uptake.

7.1 Impact on system load profile

Impact on current load profile

Figure 17 presents the average daily dispatch from different power plants in Kenya during one year (for the period between 1 July 2011 to 30 June 2012).

Figure 17 Effect of 100 MWp of solar PV on current load profile39

This has been aggregated by power generation technology. It shows that:

The peak lasts approximately 4 ½ to 5 hours – starting at 18:00 and extending through 22:30. This peak is caused by the residential customers.

39 Consultant analysis based on 1 July 2011 to 30 June 2012 hourly dispatch data as provided by KPLC for all main-grid connected power plants in the Kenyan system.

100 MWp solar PV

Displaced generation



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Primarily hydro and thermal generation are used to meet this peak demand. Thermal generation is also necessary throughout the day and represents 33% of the total energy generated.

The expected maximum power output of 100 MWp of solar PV is superimposed on the current load profile and dispatch graph in Figure 17. This shows that with the current energy mix and load profile, solar PV would:

Displace thermal generation. A more detailed analysis on what specific sources and costs solar PV would displace is presented in Section 8.

Contribute a maximum of 10% of the load during its peak at around noon and a total contribution to power generation of 1.6%.

Not make a significant contribution to power generation during peak demand hours based on the current load profile and generation mix.

It is also important to note that additional solar PV capacity could, in addition to displacing thermal generation, partially address current suppressed demand. The LCPDP of 2011 estimates that in the Kenyan system there is a suppressed demand of about 100 MW consisting of:

System load outages at the time the peak demand occurred.

Loads switched off by industrial customers at peak to avoid running their plants under poor voltages.

Customers disconnected from the system for various reasons.

New customers awaiting to be connected having paid connection charges but not yet connected.

Impact on future load profile

According to the demand assessment of Section 5.5, the 100 MWp of net metering systems in a maximum uptake scenario could potentially be achieved in 5 years, i.e. by 2018. The impacts on solar PV net metering systems should therefore be compared with the projected load profile and energy mix for that year.

Based on the LCPDP of 2011, energy generation in 2018 more than doubles that of 2013 and installed capacity is to increase from 2,000 MW in 2013 to 5,113 MW in 2018. Most of the power production is to come from geothermal (41%), followed by imports from Ethiopia (18%), hydro (14%) and coal (14%). Thermal generation from diesel is still expected to contribute 3% to the energy mix. The projected energy mix is summarised in Figure 18 below.



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Figure 18 Projected energy production and energy mix

The 2018 load profile is shown in Figure 19 below based on a simulated dispatch.

Figure 19 Projected load profile and dispatch 2018

In the 2018 scenario, assuming similar load profile characteristics to at present, the impact of 100 MWp of solar PV in the system would be to:

2018

100 MWp solar PV

Displaced generation



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Displace diesel based thermal generation.

Contribute a maximum of 3.4% of the load during its peak at around noon and a total contribution to the power system of 0.7%.

Make only a limited contribution to power generation during peak demand hours in 2018.

This scenario is based on the LCPDP of 2011 and does not consider new developments such as fast-tracked coal and natural gas power plants on the coast as presented in the Investment Prospectus 2013-2016.40 Nor does not take into account any small-scale embedded generation from renewables nor any other large-scale renewable power plant that is not committed but may come online by 2018.

7.2 Technical issues of solar PV grid interconnection

The 2011 report from GIZ assesses the technical and economic aspects of net metering in Kenya (GIZ 2011). It includes a section addressing:

Compatibility of solar PV net metering with the Kenya Grid Code.

Relevant technical issues of distributed PV generation (such a grid stability and safety).

This report, as well as other resources (e.g. SABCS 2012) states that a frequency of 50 Hz can be technically controlled and actively supported by modern inverters. Modern solar PV technology can play an active role in voltage control and should not to be seen longer as an “additive” power resource. With weather forecasting and geographical distribution, which helps to mitigate as a whole against any extreme variations in the power output of individual installations, PV becomes a predictable power resource with a low default rate.

The 2011 GIZ report provides recommendations on additions to the Kenya Grid code for inverter based generators, or generators connected to the LV grid. These are extracted and presented in Annex 2 of Volume 2 of the report. The Annex also provides recommendations on adherence to other relevant sections of the Grid Code and notes other standards that could be applied.

40 Ministry of Energy and Petroleum (September 2013) 5,000+ MW by 2016: Power to Transform. Investment Prospectus 2013 – 2016.


The economic impact of net metering on Kenya Power

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8 The economic impact of net metering on Kenya Power

In this section we identify and quantify the possible positive and negative economic impacts of introducing net metering on Kenya Power. This analysis is important because in Section 10 we use the quantified costs and benefits to propose a net metering tariff that ensures that that net metering is neutral or beneficial to the utility.

As noted in the Executive Summary and Introduction, an updated assessment to some of the findings presented here based on more recent information and stakeholder input is found in Volume 2, Annex 1. The Annex 1 findings form the basis for the recommendations in this report.

In addition to the impact on Kenya Power (discussed in the following sub sections), net metering will also have wider impacts to Kenyan society. These include:

Economic development – through technology innovation, local industry, and job creation.

Environmental benefits - net metering would displace thermal generation from diesel or heavier fuels. This would have positive environmental benefits as emissions of CO2, NOx, SOx and PM are reduced.41

8.1 Approach to calculating the costs and benefits

We evaluate the impact of net metering on the utility from a rate impacts perspective based on the methodology proposed by the Solar America Board for Codes and Standards (SABCS 2012).42 This approach includes some aspects of the “Utility Cost Test” as described in Utility and Customer Economic Impacts of Net Metering for Distributed Renewables (NERA 2013) but differs from alternatives such as the Total Resource Cost test.43 A generalized approach to rate impacts was selected for this assessment due to the inclusion of a selected range of considerations in determining costs and benefits with some emphasis on the utility perspective and its focus on the experience in the US, which has the most studies on the impacts of net metering.

The costs of net metering are often argued to be the utility’s lost revenue and any associated administrative costs. Every kilowatt-hour (kWh) generated by a net metering customer means one less kWh sold by the utility at retail rates. The retail rate in question depends on the type of customer. Residential and small commercial customers (DC and SC) have a bundled rate that covers both their utility’s fixed and variable costs, while large commercial and industrial customers (CI1 to CI5) have an “energy” charge based on kWh for variable costs and a “demand” charge based on the customer’s peak usage, measured in kVA, for fixed costs.

41 Assuming diesel consumption of 500L/MWh, 100 MWp of solar PV would have the potential of displacing almost 90,000 cubic meters of diesel per year. Avoided CO2 emissions would amount to approximately 230,000 ton CO2/year. Given the prolonged downward trend in prices for Certified Emission Reductions, CO2 emission reductions are not expected to have a significant contribution to NEM benefits in monetary terms.

42 Keyes, Jason B. and Joseph F. Weidman (January 2012). A Generalized Approach to Assessing the Rate Impacts of Net Energy Metering. Solar America Board for Codes and Standards Report.

43 Heidell, Jim and Mike King (June 2013). Utility and Customer Economic Impacts of Net Metering for Distributed Renewables. NERA Economic Consulting paper.



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On the benefits side of the rate impact calculation, the three studies reviewed in SABCS 2012 indicate that net metering allows utilities to save fuel expenses, avoid some line losses, and realise at least some capacity benefit.

The analysis and results of such studies are utility-specific, but the methodology should not be. If benefits exceed costs, then regulators may want to consider lifting restrictions on net metering and crediting net metering customers for the net benefits they provide. If costs exceed benefits, then other ratepayers are subsidising net metering customers, and regulators must decide whether externalities such as reduced pollution, job creation, and resource diversity justify the subsidy.

For the specific case of Kenya, the benefits and costs of net metering shown in Table 15 have been identified and many of them are quantified in the following sub-sections.

Table 15 List of benefits and costs of net metering to Kenya Power

Benefits to the Utility Costs to the Utility

Avoided energy purchases NEM Bill Credits

Avoided T&D losses Program administration

Avoided capacity purchases Cross-subsidy impact

Avoided T&D Investments and O&M Tariffs not reflecting fixed costs

Avoided RES Generation Purchases Connection/approval costs (meter, technical inspection, etc.)

Reliability benefits Power planning / system reconfiguration

8.2 Summary of the quantified benefits and costs

In Figure 20 and Table 16 below we summarise our calculation of the costs and benefits of net metering to Kenya Power.

The benefits of net metering would be higher if considering avoided capacity purchases, avoided T&D investments and reliability benefits. As we explain below, these are however very difficult to quantify, especially given that there is little history or data of solar PV on the grid in Kenya to analyse.



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Figure 20 Costs and benefits of net metering

Table 16 Costs and benefits of net metering in USD ‘000

Avoided energy purchases

Avoided T&D losses

NEM bill credits

Admin costs

Tariffs not reflecting fixed costs

Cross subsidy impact

Balance

Balance per kWh

USD/kWh

2012 220 38 -282 -11 0 0 -35 -0.033

2013 3,004 451 -3,855 -141 -101 0 -642 -0.046

2014 5,081 762 -6,520 -232 -291 0 -1,200 -0.052

2015 8,594 1,289 -11,027 -383 -764 -5 -2,297 -0.060

2016 14,534 2,180 -18,650 -632 -1,515 -5 -4,088 -0.065

2017 24,581 3,687 -31,542 -1,043 -2,948 -17 -7,282 -0.070

2018 41,573 6,236 -53,345 -1,721 -5,154 -71 -12,482 -0.073

In the following subsections we describe our calculation of each of the costs and benefits in detail.

8.3 Calculation of benefits

Avoided energy purchases

This section analyses what source of energy is being displaced by solar energy and its associated cost.

Figure 21 below summarises Kenya Power’s power purchase costs, calculated from the Annual Report of 2012. Power purchase costs are divided into basic costs---aimed at paying fixed variable costs of the power generators excluding fuel costs---and fuel costs. Kenya Power is required to recover cost of fuel used to generate power. This is remitted in total to thermal generators which generated that power.



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The cost of energy from thermal generators (Aggreko, Tsavo, Rabai power, Iberafrica, etc.) is the highest. The cost figures for thermal generators operated by Kengen are not available given that Kengen costs are aggregated and include a variety of energy sources (hydro, geothermal, thermal, etc.).

Figure 21 Power purchase costs for Kenya Power (2012)44

Based on dispatch information provided by Kenya Power and the merit order of power generation plants (based on the above costs) and assuming no grid congestion, it is possible to determine what sources of energy would be displaced by solar net metering systems today. Figure 22 below presents the power dispatch for 15 May 2012 (a Tuesday in middle of the month was considered a representative day). Based on the merit order of power plants, it is clear that energy being displaced is thermal generation, including Aggreko emergency plants, which have the highest cost (fuel cost is 33 USDc/kWh).

44 Consultant analysis based on Kenya Power & Lighting Company Ltd (2013) Annual Report and Financial Statements for the Financial Year Ended 30 June 2012.



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Figure 22 Power dispatch 15 May 201245

In calculating the future avoided energy purchases from thermal power plants the following assumptions were made:

Assuming that certain fixed costs of thermal generators cannot be offset/displaced by net metering, only fuel cost has been considered relevant

The cost of fuel was calculated as an average of the current cost for Aggreko, Tsavo Power, Rabai Power and Iberafrica. Fuel cost has been escalated at 2.5% p.a.

Avoided transmission and distribution losses

No matter which type of generation is offset, line loss savings are an important benefit of net metering. According to the Kenya Power Annual Report of 2012 system losses accounted for 17.3% of total energy generation (compared to 16.2% in the previous year). Increasing T&D losses are the result of extensive expansion of the electricity distribution network, and increased transmission of electricity from the Coast from the newly commissioned Kipevu III generation plant. Of these, the majority are losses at the distribution level (transmission level losses in Kenya are in the order of 3-4%).

In contrast, net metering generation occurs at the customer’s site, with almost no line loss. Excess generation from a net metering facility can be expected to be consumed by neighbouring consumers

45 Consultant analysis based on hourly dispatch data for 15 May 2012 (00:00 – 11:59) as provided by KPLC for all main-grid connected power plants in the Kenyan system.

Aggreko 33 USDc/kWh

Iberafrica 20 USDc/kWh



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with negligible line losses (there are very modest losses associated with excess generation stepping up to utility line voltage then back down when used nearby on the same circuit).

For the purposes of estimating and valuing avoided T&D losses, an average of 15% T&D losses has been used. This does not take into account fixed and unavoidable T&D losses (such as transformer losses) that may not be addressed by distributed generation. However, net metering system “lost” production due to grid downtime estimated at 4 - 6.5% is also not considered in the analysis. Avoided T&D losses of 15% are therefore considered appropriate. For CI2 customers served at 11 kV the avoided losses are lower given that they do not use the LV distribution network. Given however that CI2 participation is 4% this simplification is acceptable.

Avoided T&D losses have been valued at the cost of energy of thermal generation during daylight hours, the same as for the avoided energy purchases.

Avoided capacity purchases

With peak demand in the Kenyan system typically occurring in the late afternoon/evening, the ability of solar to provide significant capacity benefits is reduced. Net metering studies for different utilities in the USA were reviewed and they all differed in their treatment of capacity benefits. A study by the Interstate Renewable Energy Council in the USA (IREC 2012) states that capacity benefits can be considered real and incremental, with aggregate distributed solar generation far more stable and predictable than the obviously intermittent nature of individual solar facilities. However, without historical data for solar energy in the Kenyan grid the estimation of capacity benefits is would be contentious. At this stage capacity benefits are not quantified and it is proposed to consider these at a later stage, after grid-connected solar PV reaches a greater scale in Kenya.

Avoided T&D Investments and O&M

T&D investment deferrals stem from decreased customer load at the feeder, substation, and transmission levels, and can include deferrals of investment and postponing of investment in T&D upgrades. Same as for avoided capacity purchases, with peak demand occurring in the evening, the benefits of net metering in avoiding T&D investments can be considered negligible at this point.

Avoided RES Generation Purchases

Net metering is viewed as a means by which countries can achieve renewable energy targets. When these targets are mandated by law, the value of avoided RES generation purchases can be quantified. This is however not the case for Kenya, where there are not compulsory RES quotas or commitments.

Reliability Benefits

The ability of decentralized generation to provide ancillary services and var support has been widely acknowledged for inverter-based systems. However, output voltage is typically pre-set rather than being reactive to utility grid voltage, so the ability to provide support is not used at present. However, this ability is very likely to be tapped, at least for larger solar facilities, and could add significant value. Previous studies for utilities in the USA (IREC 2012) have set var support and backup power values at zero, but properly directed that those values should be estimated.



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At this stage, and without substantial grid-connected solar PV history in the Kenyan system, this benefit is not quantified and will be left for a future analysis.

8.4 Calculation of costs

Use of net metering bill credits during peak times

When net metering customers produce energy in excess of their consumption and this excess is exported to the grid, the utility credits energy for these customers. This credit is consumed during hours when energy production from the net metering customer is below the energy demand. Energy credits will normally be consumed during evening hours (peak demand hours, when the cost of energy is highest) or during night and early morning hours (when demand is low and energy is less costly).

Figure 23 Net metering and time of use cost of energy

Kenya Power is currently conducting a pilot of differentiated time-of-use (ToU) tariffs for selected customers. A ToU tariff structure would allow transparent valuation of the energy exported to the grid by net metering customers versus the energy consumed at a different time of the day. At this stage however, the cost of net metering credits can only be estimated.

As shown in Figure 21 and Figure 22 above, the marginal cost of energy during peak demand is much higher than during daylight hours. Fuel costs remitted to Aggreko, for example, are 57% higher than the average cost of fuel (these have been excluded in the revised assessment found in Annex 1 of Volume 2 of this report). It can also be assumed that 50% of the energy consumed by net metering customers occurs during the 4 to 5 hours of peak demand and the remaining 50% during the rest of the day, when energy cost is lower. Based on these assumptions, the average cost of net metering credits can be considered 25% higher than the benefit of avoided energy purchases during daylight hours. This is very similar to what has been experienced in Sri Lanka since the adoption of net metering.



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Program administration costs

The other aspect of net metering costs is the utility’s administrative expense. Most utilities use proprietary billing software that is costly to adapt for net metering. Therefore, in the short term many utilities use manual billing for net metering customers to avoid incurring a large cost for a relatively small group of customers. However, over the medium to long term, changes to a utility’s billing software to support evolving energy use patterns—e.g. differentiated time-of-use tariffs—will occur in the ordinary course of business. Logically, updating billing software to handle net metering program participants can occur as part of this longer-term evolution.

At this stage, the program administration costs have been estimated based on costs reported by utilities in the USA, where net metering has achieved scale. The IREC 2012 study indicated that reported costs reported by utilities varied significantly (between 3 and 18 USD/customer per month). As a first estimation, the program administration costs have been estimated at the average of reported costs in the USA of 9 USD/customer/month. Costs in Kenya will most likely differ from those in the USA, but the contribution of program administration to overall costs is however bound to be low (based on current assumption it is only 3% of total net metering costs for the utility).

Cross-subsidy impacts

In the current Kenya Power tariff structure, consumers below 50 kWh/month pay a subsidized basic energy consumption charge of 2.00 KES/kWh. This compares to a residential customers’ charge of 8.10 KES/kWh for energy consumption ranging between 51 and 1500 kWh/month. It is however important to note that the fixed charge of 120 KES/month at such low consumption levels is a major component of the electricity bill (per kWh, it is much higher than for any other category of consumer).

Table 17 Tariff structure for DC customers (<50 kWh/month) vs COSS 2013 requirements

Year Fixed charge Fixed charge

per kWh46 Energy

charge47 Total

Tariff requirement COSS 2013

Subsidy requirement

Cost implication for rest of consumers

KES/month KES/kWh KES/kWh KES/kWh KES/kWh KES/kWh KES/kWh

2012 120 6.57 9.59 16.16 12.56 None None

2013 120 6.57 6.88 13.45 12.56 None None

2014 120 6.57 7.68 14.25 14.13 None None

2015 120 6.57 8.02 14.59 15.03 0.44 0.012

2016 120 6.57 8.16 14.73 14.97 0.24 0.007

2017 120 6.57 8.37 14.94 15.44 0.50 0.014

2018 120 6.57 8.37 14.94 16.23 1.29 0.036

46 Fixed charge impact on the kWh rate based on average household consumption of 18 kWh/month

47 Basic cost of 2 KES/kWh plus fuel cost. For 2013 onwards, the simplified energy charge recommended in the COSS 2013 is used.



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Consumers below 50 kWh/month are also subject to paying fuel costs. Considering these additions to the basic energy cost, the cross subsidy requirements are practically negligible, as evidenced by Table 17.

This analysis is based on costumers consuming less than 50 kWh/month, which is currently 3% of the Kenya Power customer base. It is however important that only customers consuming below 50 kWh/month benefit from the subsidy. If the subsidized rate is available for the first 50 kWh of all DC customers (26% of the customer base), then the cross subsidy requirements would be much higher.

Tariffs not reflecting fixed costs

Net metering solar facilities primarily offset variable energy charges. The fixed component of electricity bills for residential and small commercial customers cannot be offset and the demand component of the demand-metered customers (commercial and industrial) remains practically unchanged.

The fixed and demand components of the electricity bill should reflect the fixed costs of the utility and therefore it is pertinent that net metering customers, who benefit from the grid usage, do not offset these charges.

The COSS of 2013 proposes a tariff increase to meet revenue requirements of Kenya Power. The proposed increase is much higher for the fixed and demand components of the tariff than for the variable energy charge. This is due to the sizable investments needed in power infrastructure. To illustrate this, for CI1 customers the COSS proposes a demand charge increase of 141% between 2013 and 2018 while the proposed energy charge increase for the same period is of 25%. This is illustrated in Figure 24.

Figure 24 Proposed tariff increase for CI1 customers (COSS 2013)

Even though the proposed tariff increases by the COSS, in particular the rebalancing of fixed versus variable charges, is meant to reflect the true cost of the utility, it can be assumed that tariff increases will in reality be lower due to pressure from consumers and political motivations. For example, if the service provided by the utility is not considered reliable---the estimated supressed



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demand of 100 MW implies power outages and loads switched off by industrial customers at peak to avoid running their plants under poor voltages---then increases in the fixed component of the electricity bills will not be tolerated.

A simplified and possibly more realistic tariff projection forecasts price increases of 30% in 10 years and fixed charges of no more than 10% of the electricity bill. This is the energy price projection currently used by the RTAP facility to evaluate RE projects offsetting grid electricity. Figure 25 presents this simplified tariff projection.

Figure 25 Simplified tariff projections for CI1 customers

Assuming that the simplified tariff projection is what is adopted in reality, net metering customers will be partially offsetting what should be (according to the COSS) fixed costs. This imbalance can be seen as a cost of net metering from the utility’s perspective.

The difference between fixed and demand charges proposed in the COSS and fixed and demand charges in the simplified projection has been calculated for each category of consumer and is presented in Table 18. Clearly the highest difference is found in demand-metered customers (categories CI1 to CI5).

Table 18 Difference in fixed/demand charge component in USD/kWh

DC (<1500)

DC (>1500) SC CI1 CI2 CI3 CI4 CI5

2012 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

2013 0.000 0.001 0.000 -0.008 -0.023 -0.024 -0.020 -0.021

2014 -0.001 0.000 0.000 -0.017 -0.031 -0.036 -0.031 -0.032

2015 -0.001 0.000 0.000 -0.030 -0.045 -0.055 -0.049 -0.050

2016 0.000 0.000 0.000 -0.037 -0.052 -0.061 -0.057 -0.058

2017 -0.001 -0.001 0.000 -0.042 -0.064 -0.073 -0.067 -0.063

2018 -0.001 0.000 0.000 -0.045 -0.067 -0.076 -0.069 -0.066



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Based on the forecasted uptake of net metering per consumer category, the overall impact of tariffs not reflecting the fixed costs of the utility is presented in Table 19. This assumes that net metering uptake will reach 100 MWp by 2018, which as discussed in previous sections is very optimistic and is not likely to be achieved.

Table 19 Net metering costs due to tariffs not reflecting fixed costs (USD ‘000)

DC (<1500)

DC (>1500)

SC CI1 CI2 CI3 CI4 CI5 Total

2012 0 0 0 0 0 0 0 0 0

2013 -1 0 0 -45 -49 -12 0 0 -106

2014 -1 0 0 -160 -109 -30 0 0 -301

2015 -2 0 -1 -450 -260 -74 0 0 -787

2016 -2 2 -1 -925 -495 -136 0 0 -1,556

2017 -5 -3 -2 -1,749 -1,003 -268 0 0 -3,030

2018 -8 -1 -3 -3,082 -1,738 -461 0 0 -5,293

Connection/approval costs

The cost of connection and approval of net metering systems (both for assessment/ administrative costs and hardware costs incurred by the utility) can be absorbed by the net metering customer as a one-time fee at the time of connection to the grid. In this way, this initial cost will not have an impact on electricity rates.

Power planning/system reconfiguration costs

If significant uptake of net metering is expected, this will need to be taken into account in future power sector planning, whether net-metered customers are considered as generators or as negative load. As power sector planning and system studies are already performed on a periodic basis and need consider a range of variables, the additional burden of net metering is not expected to be significant and such costs are excluded in this assessment.


The impact of net metering on government revenue

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9 The impact of net metering on government revenue

In this section we analyse the impact on the collection of VAT and other statutory levies.

9.1 Value added tax

Net metering with electricity “banking” implies that monetary transactions between consumers and the utility are minimized. Electricity that is not billed to customers may lead to a reduction in VAT collection from the government, especially in the case of residential customers. However, it may be possible to balance these losses against the VAT collected from the sales of solar or other renewable energy equipment intended for net metering.

The new Value Added Tax Act 2013 was implemented in September 2013. The new act has removed a number of exemptions and applies uniform tax rates for different goods and services. The implications for the net metering analysis are:

Solar PV equipment: Renewable energy materials, equipment, and accessories were previously exempt from VAT. Under the Value Added Tax Act of 2013, 16% VAT could apply. The new act does include the possibility for exemption for “imported or purchased goods for direct and exclusive use in the construction of a power generating plant, by a company, to supply electricity to the national grid approved by Cabinet Secretary for National Treasury upon recommendation by the Cabinet Secretary responsible for energy”. It is however not certain whether this would include PV or net metering systems.

Electricity sales: in 2008 VAT on electricity sales was reduced by 4% (from 16% to 12%) in a move to drastically reduce energy costs for both domestic and industrial consumers. The new VAT Act in the spirit of simplifying VAT collection could reverse this rate to 16%. The Principal Secretary can revise the tax by 25% upwards or downwards meaning it could either be raised to 20% or lowered to 12%.

In this analysis, it is assumed that a 16% VAT rate is applicable to both solar PV equipment and the electricity from Kenya Power. Figure 26 presents a cash flow analysis for the collection of VAT, REP and ERC levies for a CI1 customer with a net metering system of 365 kWp capacity.

VAT of 112,000 USD is collected by the government on the capital cost of equipment

In average 6,500 USD per year of VAT are offset by the net metering consumer. This assumes that only one third of the electricity produced is exported to the grid. The other two thirds are consumed directly and are therefore not considered in this first VAT analysis48.

VAT on capital costs more than offsets the VAT losses due to offset customer-exported electricity. NPV for the government is positive at 63,000 USD (10% discount rate).

48 Electricity consumed directly would offset VAT charges as well but since self-generation requires no net metering policy, the only relevant electricity transactions are those above direct consumption of electricity.



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Figure 26 Collection of VAT and statutory levies on hypothetical 365 kWp customer

A summary of the VAT implications for a 100 MWp net metering program is presented in Table 20. This analysis has been done for year 2018, when lower investment costs and higher electricity tariffs will be more critical for VAT collection. The resulting NPV for the whole program is positive for the government, based on the assumptions stated above.

Table 20 Net VAT and levy impact of net metering (export only)

DC (<1500)

DC (>1500)

SC CI1 CI2 CI3 Total

Aggregate capacity (MWp)

8.8 5.7 27.9 40.5 15.4 1.8 100.1

VAT losses (USD/a) 174,932 189,716 588,279 688,204 236,316 26,586 1,904,033

ERC losses (USD/a) 1,748 1,131 5,537 8,020 3,053 358 19,846

REP losses (USD/a) 54,666 59,286 183,837 215,064 73,849 8,308 595,010

NPV VAT and levies (USD)

1,677,468 106,901 3,628,437 4,772,872 2,182,887 274,341 12,642,904

9.2 Other statutory levies

Kenya Power is a designated collector of statutory levies for the Rural Electrification Authority and Energy Regulatory Commission. Net metering non-monetary transactions would result in a loss of ERC and REP levies which have been quantified in Table 20 using the same assumptions applied for VAT. For a net metering program of 100 MWp:

ERC losses would amount to almost 20,000 USD per year.

REP losses would amount to 595,000 USD per year.



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While these losses may be compensated by VAT collection from the capital cost of net metering systems, a redistribution of said benefits from the government to ERC and REA would be required.

9.3 Alternative VAT & statutory levy scenario

In the above analysis, only electricity exported to the grid has been taken into account since self-generation is permitted even in the absence of a net metering framework.

If all electricity produced by net-metered systems is considered, the impacts on VAT and ERC/REP levies collection would be negative as illustrated in Table 21 below:

Table 21 Net VAT and levy impact of net metering (all electricity)

DC (<1500)

DC (>1500)

SC CI1 CI2 CI3 Total

Aggregate capacity (MWp)

8.8 5.7 27.9 40.5 15.4 1.8 100.1

VAT losses (USD/a)

530,098 574,898 1,782,663 2,085,465 716,110 80,564 576,9797

ERC losses (USD/a)

5,295 3,427 16,778 24,302 9,252 1,085 60,140

REP losses (USD/a)

165,656 179,656 557,082 651,708 223,784 25,176 1,803,062

NPV VAT and levies (USD)

-2,917,694

-4,853,649

-11,858,291

-13,436,566

-4,007,309

-414,547

-37,488,056

In both scenarios, VAT on capital equipment costs is included due to the recent change in the VAT Act. However, if this change was to be considered as the new baseline and therefore not included, the impact of net metering on government revenue would be more significant and the NPV in the first scenario would also be negative.

On the other hand, neither scenario takes into account the ability of corporate customers to offset input and output VAT. While reduced VAT revenue from less electricity sales to residential (DC) customers accounting for 14.7 MW is really lost, depending on the nature of their business SC and C1 customers may already be offsetting VAT on purchases against VAT on sales meaning that the VAT impact could be more nuanced. Furthermore, these projections are based on a maximum net metering uptake of 100 MW by 2018, which is not likely to be achieved.


Recommended net metering credits

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10 Recommended net metering credits

In Section 8 we showed that the costs of net metering to Kenya Power are likely to exceed the benefits. Therefore, in this section we propose a net metering credit that compensates Kenya Power for its costs, thus making net metering beneficial, or at a minimum impact neutral.

We first calculate the specific net metering credit for each customer and in each year, but the differences are relatively minor, so for practical reasons we propose an average rate (expressed as a percentage of the variable component of the retail tariff) that can be used across all categories that are likely to invest in net metering. The updated findings from February 2014 are presented in Annex 1 of Volume 2 of this report.

10.1 Net metering credits calculated by customer category

and year

The implication of the costs to Kenya Power being higher than the benefits is that net metering customers should be paid less than the retail tariff for electricity exported to the grid. Table 22 below presents our calculated net metering credits using solar PV assumptions, expressed as a percentage of the variable component of the retail tariff (the unit cost plus the fuel component). These are calculated by deducting net metering costs from the projected tariffs for the different customer categories. The credits would be awarded to the net metering customer for every kWh exported to the grid.

Table 22 Net metering credit

DC (<1500)

DC (>1500)

SC CI1 CI2 CI3 CI4 CI5

2012 82% 89% 83% 79% 77% 77% 76% 76%

2013 76% 86% 77% 71% 69% 68% 67% 67%

2014 73% 84% 75% 69% 66% 65% 64% 63%

2015 70% 82% 71% 64% 61% 60% 59% 58%

2016 68% 81% 70% 63% 59% 58% 57% 56%

2017 66% 80% 68% 61% 57% 55% 54% 53%

2018 66% 80% 68% 60% 56% 54% 53% 53%



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Alternatively, the credit can be expressed per kWh, which is presented in Table 23 below.

Table 23 Net metering credit in equivalent tariff rates (USD/kWh)

DC (<1500)

DC (>1500)

SC CI1 CI2 CI3 CI4 CI5

2012 0.15 0.28 0.16 0.12 0.11 0.11 0.11 0.10

2013 0.14 0.27 0.15 0.11 0.10 0.10 0.10 0.09

2014 0.14 0.27 0.15 0.11 0.10 0.09 0.09 0.09

2015 0.14 0.27 0.15 0.11 0.09 0.09 0.09 0.08

2016 0.14 0.28 0.15 0.11 0.09 0.09 0.08 0.08

2017 0.14 0.28 0.15 0.11 0.09 0.09 0.08 0.08

2018 0.14 0.29 0.15 0.11 0.09 0.09 0.08 0.08

10.2 Average net metering credit

As shown above, we have calculated net metering credits that vary by type of consumer and with time. The variation with time is mainly due to fuel escalation rate and the growth of the solar PV share relative to overall capacity growth. We expect calculated credits will stabilise as the market matures.

Because the variation by customer category and from year to year is relatively minor, we recommend applying a weighted average rate over the 2013 to 2018 period. There is inherent uncertainty in all of our calculations, which makes the differences somewhat spurious, and a single rate will be administratively much easier to implement during the pilot phase. We calculated in October 2013 that an appropriate weighted average NET metering credit is 63% of the variable retail tariff. This was revised slightly in February 2014 to 62% as per Annex 1, Volume 2.

Table 24 shows what a 63% rate translates to in USD/kWh terms:

Table 24 Net metering credits in USD/kWh equivalent

DC (<1500) DC (>1500) SC CI1 CI2 CI3 CI4 CI5

0.14 0.23 0.14 0.13 0.12 0.11 0.11 0.11

Our analysis of project cash flows for solar PV projects suggests that, relative to the solar PV FiT, net metering will be attractive for consumer categories DC, SC and CI1 (shown in green above). This is particularly true for the DC (>1500) category due to their high retail tariff. CI2 (shown in yellow) could be indifferent between net metering and FiT, and for CI3 onwards (shown in red) FiT would be more attractive than net metering.

The returns (IRR) for the different types of consumers have been recalculated following the methodology of section 5.4 above. Table 25 below compares to Table 6. Table 25 confirms that



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discounted net metering electricity credits would be more attractive for categories of consumers DC to CI1 than the current FiT rate.

Table 25 Expected IRR of solar PV net metering systems (recalculated at 63% tariff)

DC (<1500)

DC (>1500) SC CI1 CI2 CI3 CI4 CI5

2013 9.1% 20.8% 12.2% 11.3% 9.4% 8.6% 8.2% 7.9%

2018 13.1% 28.4% 17.0% 16.0% 13.3% 12.2% 11.6% 11.4%

In the market assessment of section 5 above, practically all demand for net metering was assumed to come from consumer categories DC, SC and CI1 (83%). The proposed net metering crediting rate of 63% of the variable component of the retail tariff is therefore not expected to have a significant impact in the maximum market size of 100 MW.

It should be noted that the net metering discounted credit has only been applied to electricity exported to the grid rather than to the complete output of the RE systems. The rationale behind this assumption is that RE systems are being installed for self-generation/self-consumption without grid interaction and offsetting the full electricity tariffs in absence of any supporting policy. A NEM policy would only be relevant for the portion of electricity that is exported to the grid against credits.

10.3 Credits for other RE technologies

While the focus of this study and our calculations above is on solar PV, it is important to anticipate the rate impacts of other RE technologies eligible for net metering.

Bioenergy (biogas or biomass gasification) depending on specific circumstances can often be stored for some time and is therefore less dependent on the grid. If grid-interactive, the storage flexibility allows bioenergy systems to have a greater contribution during peak hours, when electricity is most expensive. If the systems are run continuously, avoided capacity purchases as well as avoided T&D investments could be more easily quantified. However, given that small scale systems do not necessarily work continuously, differentiated Time of Use tariffs would be required to properly determine the value of the electricity exported to the grid. Overall, it can be estimated that net metering benefits stemming from bioenergy electric generators would be higher than those for solar PV.

Mini/micro- hydro and wind similarly are variable during the day and seasonally, but are not limited to daylight hours as is the case of solar PV. This would also grant these systems higher benefits in terms of avoided energy purchases and avoided energy infrastructure investments than for solar PV.

For an initial/pilot stage of net metering, we recommend adopting a uniform credit across all RE technologies. The credit suggested for solar PV net metering would guarantee that benefits remain above costs from the utility’s perspective.



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Since we expect other technologies to bring greater benefits than solar PV net metering systems, applying a uniform credit for all technology types should ensure that Kenya Power is not adversely affected by the introduction of net metering.


Recommendations on implementing a net metering

programme

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11 Recommendations on implementing a net metering

programme

This report provides a rich compendium of analysis of the current and future net metering in Kenya, together with insights from the experience of other countries. Our succinct recommendations arising from the analysis are as follows:

11.1 Phase 1of the programme

Launch phase 1 of a net metering programme

Because our analysis shows that net metering has significant potential to reduce the overall cost of energy, there are no significant technical impacts associated with net metering in Kenya, and that Kenya Power can be fairly compensated for the net costs it will incur, we recommend launching phase 1 of a net metering programme.

In keeping with best practice internationally, phase 1 should be reasonably conservative, thereby using it to test the concept before widening eligibility for the programme and increasing its sophistication. An appropriate time period for phase 1 could be two to three years.

Make all renewable energy sources eligible for the programme

While the assumption in this assessment is that solar PV will be the predominant technology deployed, candidate small hydro and biogas/biomass distributed generators have also been identified. Allowing customers to choose the form of renewable technology should maximise the uptake of net metering and ensure that the most efficient technologies are chosen.

Only allow banking, not payment for net exports

During phase 1, net metering customers should be able to bank their electricity exports to the grid (i.e. any surplus is carried forward and used to offset consumption in future periods), but not be paid for net exports. This keeps the programme administratively simple to implement, easy for customers to understand, and clearly delineates net metering from feed-in tariffs (FiTs) which are paid for renewable electricity generation by larger producers.

Apply a net metering credit of 62% of the retail tariff

As detailed in Annex 1 of Volume 2 of this report, during phase 1 we recommend applying a credit of 62% on the variable component (unit + fuel charges) of the retail tariff to all net metering electricity that is exported to the grid for all technology types across all customer categories.



programme

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Apply an individual system cap of 500 kW

We recommend only allowing systems sizes of 500 kW or less to participate in the net metering pilot programme. This is common around the world, with most countries applying individual caps (or had them when the programme was first started). We recommend it in Kenya for a number of reasons, including (1) Kenya will be the first low income country to adopt net metering, (2) a 500 kW cap will avoid confusion with the FiT (which applies to systems above 500 kW or 200 kW in the case of biogas only), (3) larger systems (or those connecting at medium or high voltage) will have more involved technical requirements. The individual system size should furthermore be limited to the existing contract or demand size. This is to prevent oversized systems that may operate as net exporters and to minimize the need for distribution network upgrades. Future consideration can be given to lifting the cap once the pilot programme is completed.

Apply a total cap of 100 MW

We recommend that for phase 1 of the programme a 100 MW cap should apply on the total net metering capacity and be separate and additional to the technology-specific caps stipulated in the Feed-in Tariff Policy49. Most countries with successful net metering programmes started with a cap, normally either fixed in MW or as a percentage of peak demand. The cap should be reviewed and removed as soon as experience of net metering warrants this.

Apply an application fee

In addition to the net metering credit, Kenya Power should be allowed to charge a (a) a non-refundable application fee and (b) a site visit assessment fee and (c) a site visit testing, commissioning and certification fee to compensate the upfront administrative burden of approving an net metering system. The customer should also pay the cost for the purchase and installation of new meters and system testing. No other fees (e.g. for billing changes) should be charged to customers.

Only allow dual metering

Although a single reverse-flow or bi-directional meter would be simpler and possibly cheaper to implement, this would not allow for the proposed tariff differentials (between the retail tariff and the net metering tariff which is proposed at 62%) to avoid any impact on the utility and other ratepayers. A two-meter system would permit the application of a time-of-use tariff in the future and will facilitate the collection of more detailed system data for monitoring. This recommendation should apply equally to pre-paid meter customers. A single smart meter may be able to overcome these limitations but at increased upfront expenses. Once installed and tested, meter ownership should be transferred to the utility.

49 Most of the NEM capacity is expected to be taken up by PV. In the FiT framework, the cap on PV is also 100 MW. Therefore, the effect of accepting the recommendations in this report would be to set a total PV cap of 200 MW. This can be reviewed and adjusted as experience is gained of the two programmes.



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Conduct utility site assessments for initial installations

In some countries automatic approval and system installation is permitted for systems up to a certain size, normally 10, 20 or 30 kW, which is generally considered best practice internationally. However we do not recommend applying this at the outset in Kenya, given that net metering it still largely an untested concept. Instead we recommend that Kenya Power conduct a site visit for at least the first 10 installations of each technology type and customer category to identify any major issues that may arise and ascertain if there are any specific protection or interconnection requirements. Nevertheless, the net metering regulations that may be adopted should include provisions for the possibility of simplified procedures for smaller systems to allow for this eventuality.

11.2 Phase 2 of the programme

The following changes to the net metering programme should be considered in phase 2:

Allow ‘settlement’ for net metering exports by customers who opt into the scheme, in addition to offering the existing ‘banking’ option. In other words, customers will have to options to choose from: (1) bank their exported energy and offset it against future consumption (as proposed under Phase 1), or (2) get paid a per kWh tariff by Kenya Power for their net exports.

Increase the individual cap on system size (500 kW), to allow participation of larger customers.

Increase or remove altogether the cap on total net metering capacity (100 MW)

Recalculate the value of net metering credits (62%), making use of significantly more data which will then be available.

Consider simplified or automatic approval procedures for proposed net metering facilities that meet certain requirements (e.g. systems of 10 kW or less that do not inject more than 15% of shared feeder line capacity could receive automatic approval with no utility site visit).

Next steps:

To make the net metering pilot programme operational, the next step will be to finalise the draft net metering regulations and application procedures for net metering. Draft documents submitted alongside this report have been prepared based on best practice in other countries drawing on materials provided in Volume 2 of this report.

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