the Final Net Metering Assessment Report Volume 2

Transcription

EUEI-PDF Kenya 2013 Project
Renewable Energy Regulatory Capacity Development
Assessment of a net metering programme in
Kenya
Volume 2: Annexes
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
Contents
Contents
A1
February 2014 report update
1
A1.1
Changes in the model
1
A1.2
What is not included in the model
9
A1.3
Metering
10
A2
Technical connection standards
12
A2.1
General technical standards
12
A2.2
Solar PV/inverter-based systems
13
A2.3
Sample interconnection diagrams
15
A3
References
20
A4
Contribution to renewable energy targets and economic development
22
A5
Electricity tariff projections
27
A5.1
Tariff levels from July 2008 to November 2013
27
A5.2
Projection of electricity tariffs
28
A6
Proposed application and implementation process
31
A7
International case studies
36
A7.1
United States of America
36
A7.2
Denmark
48
A7.3
Tunisia
58
A7.4
Mexico
66
A7.5
Sri Lanka
70
A7.6
Morocco
78
A7.7
Uruguay
82
A7.8
South Africa
87
A7.9
Jamaica
99
A7.10
Brazil
Kenya net metering assessment
107
i
Tables and Figures
Tables and Figures
Tables
Table 1: Net metering costs to the utility due to tariffs not reflecting fixed costs (USD '000)
2
Table 2: Net metering customer category IRRs (original scenario, 2.7% tariff escalation)
4
Table 3: Net metering customer category IRRs (new scenario, 0% tariff escalation)
5
Table 4: Solar PV net metering system assumptions in the main report
6
Table 5: Net metering residential customer IRRs (67% direct consumption)
7
Table 6: Net metering residential customer IRRs (new scenario, 33% direct consumption)
7
Table 7: Summary of changes in the net metering tariff model
8
Table 8: Solar PV net metering customer IRRs in October 2013 scenario
9
Table 9: Solar PV net metering customer IRRs in revised February 2014 scenario
9
Table 10: List of suggested technical standards for net metering in Kenya
12
Table 11 Renewable energy targets
22
Table 12 Electricity tariffs (2008-2013, excluding December 2013)
27
Figures
Figure 1: Projected reduction in Fuel Cost Charge (2013-2016)
4
Figure 2: Solar PV net metering customer generation versus consumption
5
Figure 3: Sample interconnection diagram for distributed generation
16
Figure 4: Typical single-line diagram for the protection of a synchronous generator
17
Figure 5: Typical single-line diagram for the protection of an induction generator
18
Figure 6: Typical single-line diagram for the protection on an inverter
19
Figure 7 Simplified tariff projections for CI1 customers
29
Figure 8 Proposed tariff increase for CI1 customers (COSS 2012)
30
Figure 9 Flow diagram of proposed net metering application and approval process
35
ii
ANNEXES
ANNEXES
iii
A1
In November 2013 the Energy Regulatory Commission (ERC) approved a new Schedule of Tariffs, the
first such since 2008. The Schedule of Tariffs was gazetted in January 2014.
This development necessitated a review of the economic assessment performed in the October 2013
version of the report to evaluate impacts on Kenya Power and assess the effect on the financial
attractiveness of net metering from the customer’s perspective. The update also takes into account
additional stakeholder comments received since October 2013.
Rather than amend the main body (Volume 1) of the report to reflect the changes, which have
important implications, the relevant findings are presented here and the differences are noted for
easy comparison.
Nevertheless, the Executive Summary, Introduction and Recommendations in Volume 1 were
modified to take into the account the revised findings. Minor corrections were also made to the
report and an example of potential development benefits of net metering made more prominent in
Section 3.2. This Volume 2 also sees some changes to Annex A6 on the proposed net metering
application and implementation procedures and a new Annex 0 on technical standards.
A1.1
Changes in the model
Five changes were made to the input assumptions in the net metering tariff model. Two of the
changes are based on the new Schedule of Tariffs and the other three are adjustments made to take
into account stakeholder feedback. The impact of each change is noted in isolation and then the
aggregate effect is assessed.
2013 Schedule of Tariffs
The new Schedule of Tariffs includes stepped tariff increases for December 2013, July 2014 and July
2015 across all categories of consumers. Taken across the period the increments range from 15% to
19% per annum. The increase affects the three main components of the electricity bill (fixed charge,
basic charge and demand charge).
The new schedule of tariffs also introduces new statutory levies:

Security support facility (applicable per kWh consumed): security for Kenya Power PPA
payment obligations to the Lake Turkana Wind Power project.

Water levy (applied per kWh): paid to the Water Resource Management Authority for
water used for hydropower.
Baseline international exchange rates were also revised to current market rates for the purpose of
the Foreign Exchange Rate Fluctuation Adjustment. This sees for example the USD-KES rate improve
from 64.9 (2008) to 84.6 (2013).
1
Impact on net metering customers
From the perspective of a prospective net metering customer, increases in the variable (per kWh)
component of the electricity bill help increase financial attractiveness. The increase of the basic
consumption charge in the new Schedule of Tariffs ranges from 15 to 19% annually on average
depending on the consumer category, albeit with a slight decrease in the transition from June 2014
to July 2015. The increase over the period, however, only applies to the basic consumption charge
and not the fuel cost or other variable (per kWh) adjustments.
The October 2013 version of this report (Volume 1) estimated the profitability of net metering
systems based on long-term projections of electricity prices using a simplified approach based on the
2013 Cost of Service Study. The new Schedule of Tariffs only provides tariff information through
2016 for the normative components of the tariff and therefore does not provide sufficient
information on which to estimate the long-term impact or return on investment for net metering
customers. We therefore retain the tariff estimates provided in the October version of the report in
Volume 1, but subject the model to (a) adjustments to improve the assumptions and (b) testing of
the new tariff and fuel cost scenario in this Annex A1.
Impact on the utility
Section 8.4 of the main report estimates the costs to the utility associated with net metering. The
sub-section entitled ‘Tariffs not reflecting fixed costs’ penalises net metering customers for being
able to offset components of the electricity bill that should be fixed charges but, due to imbalances
in tariff structure, are charged as variable component costs.
The 2013 Schedule of Tariffs introduces increases in both fixed and variable charges and the impact
of this has been recalculated in Table 1 to show the changes in the cost to the utility that will need to
be absorbed by net metering customers in order to maintain revenue neutrality for Kenya Power.
Table 1: Net metering costs to the utility due to tariffs not reflecting fixed costs (USD '000)
With simplified tariff projection based
on the Cost of Service Study (October
2013)
With new Schedule of Tariffs (February
2014)
2012
0
0
2013
-106
-106
2014
-301
-228
2015
-787
-673
2016
-1,556
-1,389
2017
-3,030
-2,784*
2018
-5,293
-4,967*
* The impact after 2016 was calculated assuming that the approved tariff for July 2015 remains constant
through 2018.
The impact of the new tariff schedule (in comparison to our original tariff projection) is a cost
reduction to the utility of 5.3% in 2018.
2
Impact on proposed net metering credit
The effect of the above cost reduction on the proposed net metering credit is an increase from 63%
to 64%.
Impact on government revenue
Section 9 of the main report presents the impacts of net metering on the collection of VAT and
statutory levies (ERC and REP). The new tariff schedule introduces new levies that will be similarly
partially offset by net metering customers.
Expected decrease in Fuel Cost Charge
Tariff projections used in the October 2013 version of the report were based on the Scenario A of
the 2013 Cost of Service Study (COSS). The basic consumption charge (energy charge, per kWh) in
the retail tariff proposed in the COSS includes the Fuel Cost Charge. This was calculated by the COSS
consultant based on the forecasted revenue requirements of the utility.
A simplified tariff projection, based on a constant escalation rate of 2.7% p.a., was used in the
economic assessment as presented in the main report. This approach resulted in a tariff projection in
October 2013 that was already below the COSS projections.
With the new power sector planning encapsulated in the 5,000+ MW by 2016: Power to Transform
investor prospectus,1 which fast-tracks coal, natural gas and more geothermal, the government
expects that customer electricity bills will reduce thanks to lower fuel costs and the revised foreign
exchange rate baseline.
An ERC media briefing note of November 2013 provides projections of a rapidly decreasing fuel cost
component of the tariff (41% p.a. for the 3-year control period) which, in spite of the increase in the
normative component of retail tariffs (15 to 19% p.a. depending on consumer category as noted
above), is expected to bring down the overall cost of electricity.
Ministry of Energy and Petroleum (September 2013) 5,000+ MW by 2016: Power to Transform. Investment
Prospectus 2013 – 2016.
1
3
Figure 1: Projected reduction in Fuel Cost Charge (2013-2016)2
To take into account the new information, the model has been changed as follows:

A new scenario of constant electricity tariffs has been tested (escalation rate equals
0%, versus the 2.7% noted above).

Emergency Power Producer fuel costs have been removed and fuel cost inflation set
to 0% in contrast to the 2.5% assumption in previous iteration.

With decreasing fuel costs, the value of avoided energy purchases for the utility due to
contributions from net metering (net metering systems are assumed to displace fuel as
per section 8.3 of the main report, ‘avoided energy purchases’) also reduces. The cost
of net metering credits to the utility will similarly decrease (see section 8.4 of Volume
1, ‘Use of net metering bill credits during peak times’).
Impact on net metering customers
Given that the economic rationale of net metering customers is to offset electricity tariffs, the effect
of eliminating the tariff escalation factor reduces financial attractiveness as show in Table 2 and
Table 3 below:
Table 2: Net metering customer category IRRs (original scenario, 2.7% tariff escalation)
DC
(<1500)
DC
(>1500)
SC
CI1
CI2
CI3
CI4
CI5
2013
9.1%
21.0%
12.2%
11.4%
9.4%
8.6%
8.2%
8.0%
2018
13.1%
28.8%
17.0%
16.0%
13.3%
12.2%
11.6%
11.4%
Nyang, Frederick (19 November 2013) ERC Media Briefing: Review of the Retail Electricity Tariffs for the Tariff
Control Period 2013/2014 – 2015/2016, Energy Regulatory Commission presentation.
2
4
Table 3: Net metering customer category IRRs (new scenario, 0% tariff escalation)
DC
(<1500)
DC
(>1500)
SC
CI1
CI2
CI3
CI4
CI5
2013
6.5%
18.2%
9.6%
8.8%
6.9%
6.1%
5.7%
5.5%
2018
8.8%
22.0%
12.3%
11.4%
9.1%
8.1%
7.6%
7.4%
Impact on the utility
As presented in the main report, section 8.4 ‘Use of net metering bill credits during peak times’,
solar PV net metering customers are likely to draw from the grid during peak hours in the evening,
when electricity is typically more expensive than when net metering systems produce electricity (see
Figure 2 below). This is taken into account in the model as a time-of-use cost factor.
With decreasing fuel costs, this difference is less pronounced. The October 2013 version of the
report estimated net metering credits during peak load as being 1.28x more expensive than avoided
energy purchases during the daytime. With decreasing fuel costs the difference is estimated to
reduce to 1.18x.3
Figure 2: Solar PV net metering customer generation versus consumption
Peak load/base load cost for GT (natural gas) is 1.34 (LCPDP 2011). Assuming that 27% of energy consumption
during peak hours and 25% during off-peak (see graph), net metering credits should, in average, be 1.18x more
expensive than avoided energy purchases.
3
5
Impact on proposed NEM tariff
The combined effect of the above changes in the model is an increase in the net metering tariff from
63% to 72%. This increase is due to the reduced cost to the utility of solar PV net metering customer
consumption during peak load. In this scenario energy exported during the daytime by net metering
customers has proportionately more value compared to in the October 2013 high fuel cost scenario.
Effect of all domestic customers accessing lifeline tariff
As noted in section 8.4 of the report, in the sub-section on cross subsidy impacts, we had based our
analysis on the need to cross-subsidise only domestic category (DC) customers consuming less than
50 kWh/month, which represents 3% of energy sold. This is based on the recommendations of the
COSS, as are all other input assumptions used in assessing the cross subsidy.
It is our understanding, however, that the utility applies the social/lifeline tariff to the first 50 kWh of
all DC customers. The social tariff therefore applies to 9% of the energy sold (as opposed to 3%).
Cross subsidy requirements are therefore higher than originally estimated.
Impact on proposed net metering tariff
If the higher cross subsidy requirement is translated into a net metering cost to the utility---because
net metering customers do not pay their fair share of cross-subsidisation---then the proposed net
metering credit rate decreases from 63% to 60%.
Key assumptions for net metering systems
The modelling of net metering systems included the assumptions in Table 4 below as per Section 5.4
“Demand assessment in Kenya” of the main report.
Table 4: Solar PV net metering system assumptions in the main report
System size
Residential
Direct consumption
%
System degradation
%/year
Capacity factor (avg)
%
Commercial
Industrial
67%
67%
67%
0.50%
0.50%
0.50%
20%
20%
20%
With regard to direct consumption:

67% is approximately what industrial/commercial customers (working 2 shifts, e.g.
06:00 – 22:00, and with constant load) would consume directly if they were to size their
systems to meet 100% of their energy demand.

Given that we propose to cap the size of individual systems to the contracted demand,
solar PV systems will most likely cover less than 100% of their total consumption and
direct consumption of solar energy will be even higher than 2/3.
6

On the other hand, residential customers will export much more than a third of their
production (most of the energy is consumed in the evening).
In the October version of the report 67% direct consumption was applied to all categories since most
net metering capacity is expected to be implemented by commercial and industrial customers. Now
we have changed the domestic consumption rate to 33% to better reflect the likely situation in that
category.
The system degradation and capacity factors have not been adjusted.
The effect is to reduce the IRRs of domestic category (DC) customers as per the first two columns of
Table 5 and Table 6 below by 2.7% to 5.5%.
Table 5: Net metering residential customer IRRs (67% direct consumption)
DC (<1500)
DC (>1500)
SC
CI1
CI2
CI3
CI4
CI5
2013
9.1%
21.0%
12.2%
11.4%
9.4%
8.6%
8.2%
8.0%
2018
13.1%
28.8%
17.0%
16.0%
13.3%
12.2%
11.6%
11.4%
Table 6: Net metering residential customer IRRs (new scenario, 33% direct consumption)
DC (<1500)
DC (>1500)
SC
CI1
CI2
CI3
CI4
CI5
2013
6.4%
16.9%
12.2%
11.4%
9.4%
8.6%
8.2%
8.0%
2018
9.9%
23.3%
17.0%
16.0%
13.3%
12.2%
11.6%
11.4%
Transmission and distribution losses
As per Section 8.3 of the main report, one benefit of net metering was assessed to be avoided
transmission and distribution losses. In this revision the impact has been adjusted downwards to 8%
from the previously estimated full avoided losses at 15%. This is to take better account of fixed and
unavoidable T&D losses while also recognizing the impact of lost net metering production due to
grid downtime estimated at 4 – 6.5% based on the net metering case studies.
This adjustment decreases the net metering credit from 63% to 55%.
Summary of changes in the model
An overview of the above-mentioned changes is presented in Table 7 below.
7
Table 7: Summary of changes in the net metering tariff model
Change
Effect on net
metering
customers
Effect on utility
Effect on net
metering credit
New schedule of
tariffs
Increase in retail
tariff (normative
component only),
15 to 19% p.a.
depending on
category of
consumer
All other factors
(e.g. fuel
charges)
remaining
constant,
increased
financial
attractiveness
Reduced cost of
net metering to
the utility
Increases from
63% to 64%
Decreasing fuel cost
Government
expects fuel cost to
decrease rapidly
due to introduction
of coal, natural gas
and fast-tracking
more geothermal)
Reduced
financial
attractiveness
Reduced cost of
net metering to
the utility
Increases from
63% to 72%
All DC customers
accessing lifeline
tariff below 50
kWh/month
All DC customers
accessing lifeline
tariff below 50
kWh/month, as
opposed as only
DC<50 customers
Residential net
metering
customers not
paying fair share
of tariff cross
subsidy
Increased cost
to the utility (or
to other
ratepayers)
Decreases from
63% to 60%
Direct consumption
parameter for DC
customers
Reduction from
67% to 33% for
residential users.
Residential
customers offset
less of the full
tariff rate
Increased
energy
purchase
avoided cost
benefits but
higher time-ofuse factor costs
Decrease in net
metering project
IRRs by 2.7 to
5.5%
Correction in avoided
T&D losses with net
metering
Decrease from 15%
to 8%. Most T&D
losses are fixed, not
variable.
Reduced net
metering
benefits
Increased cost
of net metering
Decrease from
63% to 55%
Resulting net
metering tariff
Reduction from
63% to 62%
Aggregate impact of the changes
As seen above, the net effect of the changes to the model assumptions to ensure no economic
impact on Kenya Power or other ratepayers and to take into account relevant comments received is
a reduction in the proposed net metering credit from 63% to 62%.
8
The lower Fuel Cost Charge projections anticipate a significant reduction in the electricity tariff. Due
to this overall decrease, profitability for net metering customers also decreases in spite of the
relatively modest change in the net metering credit.
The impact is to reduce projected solar PV net metering customer returns by approximately 3.1
and 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. Table 8 and Table 9 provide a comparison.
Table 8: Solar PV net metering customer IRRs in October 2013 scenario
DC (<1500)
DC (>1500)
SC
CI1
CI2
CI3
CI4
CI5
2013
9.1%
21.0%
12.2%
11.4%
9.4%
8.6%
8.2%
8.0%
2018
13.1%
28.8%
17.0%
16.0%
13.3%
12.2%
11.6%
11.4%
Table 9: Solar PV net metering customer IRRs in revised February 2014 scenario
DC (<1500)
DC (>1500)
SC
CI1
CI2
CI3
CI4
CI5
2013
3.3%
13.2%
8.9%
8.1%
6.2%
5.5%
5.1%
4.9%
2018
5.3%
16.3%
11.5%
10.6%
8.4%
7.4%
7.0%
6.8%
If the expected fuel cost reductions materialize, the impact on the financial attractiveness of net
metering is significant and the maximum uptake scenario is not likely to be reached. In this case if
the promotion of net metering is considered important to achieve certain objectives and realize the
potential benefits, a support mechanism may be needed.
If fuel charges do not reduce significantly or if the normative component of the variable tariff
element is increased after 2016, the proposed 62% net metering credit may need to be adjusted but
financial attractiveness for net metering customers would improve.
A1.2
What is not included in the model
As indicated in Section 8.1 “Approach to calculating costs and benefits” in Volume 1 of the report,
not all potential parameters are included or quantified due in some cases to lack of information and
in others to uncertainty of appropriateness. Nevertheless, we believe a reasonable balance has been
achieved. For example, while the impact of net metering on capacity charges may be relevant, it has
been excluded. At the same time, possible benefits of solar PV net metering customer inverters in
supporting network reliability and stability and possibly forming a key component of any future
development of a smart grid is ignored. Discussion on some further considerations raised by
stakeholders is noted here.
Net metering customer use of and payment for capacity
As noted in Volume 1 of this report, if net metering customers use capacity but do not pay a fair
share of the costs, this would increase capacity costs for other consumers. However, since net
9
metering customers will continue to pay fixed and demand charges, they already support capacity
investments. To the extent that the fixed and demand charges may not adequately reflect capacity
charges, this may indicate a distortion in the tariff structure that needs to be addressed. On the
other hand, the current tariff structure not reflecting fixed costs also penalizes net metering
customers in the calculation of the discounted credit.
Capacity charges of existing and committed generators
In the case that significant adoption of net metering would lead to the displacement of planned or
expected dispatch of existing and committed generators, there may be implications in terms of
capacity charges for under-utilized power plants. This may increase the cost of capacity relative to
energy disproportionate to what was expected at the time that Power Purchase Agreements were
signed. Such potential costs were not considered in the study since any other new generation, such
as under the Feed-in Tariff, could have a similar effect.
Energy charges including utility “delivery costs” and return on investment
Similar to the point above on net metering customers and use of capacity, it may be considered such
customers are offsetting component costs included in the energy charges, which is not fair to other
ratepayers.
The consultants have used the COSS as the reference with the best available information on utility
revenue requirements. All costs and returns needed by the utility are accounted for in the COSS and
should be properly allocated as fixed or variable charges. Although this may not be the case in the
current situation, the discounted crediting approach adopted in the model is expected to be
sufficient compensation.
A1.3
Metering
Compatibility of net metering with prepaid meters
Kenya Power has plans to roll out pre-paid meters for all domestic customers (DC) and other
categories of consumers with low energy consumption. The plan includes all DC customers and
customers in small commercial (SC) and interruptible supply (IT) categories with energy consumption
below 1,000 kWh/month. The original objective was to switch all DC consumers to pre-paid meters
by 2015, but this may be extended until 2018. Recent discussions suggest that the planned
programme roll-out may be re-assessed, but the implications of prepaid meters is nevertheless
important to consider.
Based on information from Kenya Power, with the proposed dual meter approach (one for import
and one for export), net metering is compatible with prepaid meters. This is because the prepaid
meters can be programmed to add any net metering credits from the exports when topping up. A
single smart meter could be considered as an alternative but would increase upfront costs for
potential net metering customers.
For example: If X is the number of units exported to the grid between top-ups and Y is the number of
units topped up by loading the prepaid meter, then the pre-paid meter could automatically credit
Y+(0.62*X) units for the top up. The utility may need to consider
10
Alternatively, during the first phase of implementation of net metering, interested customers could
request to remain as post-paid customers.
Smart meters and automatic/remote meter reading
Some existing utility customers most notably in the C1 commercial category have smart meters or
automatic meter readers using GSM or GPRS technology to transmit data, which makes site visits
unnecessary. The communication fees are paid by Kenya Power. This option could be applied to net
metering customers. The downside is that there are sometimes communication network outages or
congestion that can affect automatic meter reading or data transfer. In this case utility personnel
can still be deployed to manually read or collect the information.
Smart meters would also be eligible for net metering as they have both import and export scales and
could adequately account for the time-of-use adjustment factor. The use of smart meters would
have upfront resource implications. Conventional single-phase meters cost USD 8-10 whereas singlephase smart meters range from USD 40-50. Physical installation of smart meters is also more
complicated because two components of the meter are installed in different locations.
Multi-site metering
As noted in Section 2.1 of Volume 1 of this report, multi-site net metering is permitted in some
jurisdictions. This approach starts to overlap with the concept of electricity wheeling and can raise
issues of additional grid use charges. Aggregation of meters at a single location may also need to be
addressed. Multi-site net metering is not considered in this report in order to simplify the
implementation of phase I of a net metering programme.
11
A2
A review of relevant regulations and standards in Kenya indicates that existing requirements for the
interconnection and operation of distributed, embedded small-scale renewable energy generators is
largely sufficient to facilitate the adoption of a phase 1 net metering programme. The Kenya
Electricity Grid Code is included as a relevant “standard” even though it has not been officially
gazetted. It is recommended, however, that where the Grid Code is applied net metering customers
not be considered “Code Participants” as most requirements for this category of participants are
more suited to large generators.
Furthermore, simplified standards and procedures could be considered for smaller net metering
systems (e.g. 10 kW and below).
A2.1
General technical standards
A list of suggested technical standards for net metering systems to adhere to is as follows
Table 10: List of suggested technical standards for net metering in Kenya
Source or reference
Comments
The Kenya
Electricity Grid
Code
In particular:
Connection
Guidelines for
Small-Scale
Renewable
Generation Plants
(Kenya)

Schedule 3.1, network performance requirements

Schedule 3.2, connection of electrical power producers, up to and including
sub-section 3.2.5

Schedule 3.3, connection of consumers, up to and including sub-section
3.3.8

Schedules 3.5.1 – 3.5.5, generator, network, connection and load data

Section 8.4, connection of embedded generator, up to and including subsection 8.4.6

Chapter 4, metering and retail supply of electricity
In particular:

Section 4, capacity limits and connection voltage

Section 5, connection application [simplified procedures]

Section 7, generating plant connection design and operation

Section 11, testing and commissioning
12
Kenyan
regulations and
standards

Kenya Bureau of Standards standards

Energy (Electrical Installation Works) Rules

Energy (Solar Photovoltaic Systems) Regulations, 2012

IEEE Std. 519-1992 - IEEE Recommended Practices and Requirements for
Harmonic Control in Electrical Power Systems, 1992.

IEEE Std. 929-2000 - IEEE Recommended Practice for Utility Interface of
Photovoltaic (PV) Systems, 2000.

IEEE Std. 1547 – 2003 (R2008), IEEE Standard for Interconnecting
Distributed Resources with Electric Power Systems, 2008.

IEEE Std. 1547.1 – 2005, IEEE Standard Conformance Test Procedures for
Equipment interconnecting Distributed Resources with Electric Power
Systems, 2005.

IEEE Std. 1547.2 – 2007, IEEE Application Guide for IEEE Std. 1547, IEEE
Standard for Interconnecting Distributed Resources with Electric Power
Systems, 2007.
International
Electrotechnical
Commission (IEC)

IEC 61000 standard series
Institution of
Engineering
Technology (IET)

IET Wiring Regulations 17 Edition (BS 7671) for commissioning

NRS 097-2-1:2010 Grid Interconnection of Embedded Generation
Institute of
Electrical and
Electronics
Engineers, Inc
(IEEE)
South African
national standards
th
The proposed Net Metering Regulations and Net Metering Agreement accompanying this report
provide requirements for net metering system operation and disconnection.
A2.2
Solar PV/inverter-based systems
Technical considerations for the connection of solar PV net metering systems are briefly review in
Section 7.3 of Volume 1 of this report. As noted, some changes to the Grid Code should be
considered to provide for inverter-based generators and clarify the requirements. These
recommendations are taken from a 2011 GIZ report, extracts of which are repeated here:
Frequency control
Section S3.1.3 of the Kenya Electricty Grid Code:
13
“A network service provider shall ensure that within the power system frequency range 45.0
to 52.0 Hz all of his power system equipment will remain in service unless that equipment is
required to be switched to give effect to load shedding in accordance with clause S3.1.10, or is
required by the System Operator to be switched for operational purposes. Plant shall not be
required to operate in a sustained manner outside the range of the normal operating
frequency excursion band but should remain in service for short-term operation in the range
of 45.0 Hz to 52 Hz. …”
Section S3.2.6.4 states:
“…Overall response of a generator for system frequency excursions shall be settable and be
capable of achieving….a reduction in the generator's active power output of 2% per 0.1 Hz
increase in system frequency provided the latter does not require operation below technical
minimum. For initial outputs above 85% of rated output response capability shall be able to
achieve a linear reduction in response down to zero response at rated output. …”
The basic functionality to abide by these requirements is implemented in modern inverters.
However, the frequency range is wider than in Europe, thus inverters with “European settings”
might switch off more often than necessary. Default frequency range in Europe is 47.5 Hz to 51.5 Hz.
Once a significant generation capacity with PV is available, the switching-off threshold at lower
frequency becomes crucial. A premature disconnection of inverters would actually reduce power
generation when it is badly needed, during a lack of generation.
Therefore, on a long-term basis the inverter threshold for disconnection should be set to 45 Hz
during commissioning. Inverter operational bands will have to be adapted, which is technically
feasible.
Voltage behavior and Fault-Ride-Through (FRT)
Section S3.1.4 of the Grid Code states:
“…. control of voltage such that the minimum steady state voltage magnitude on the
transmission network will be 90% of nominal voltage and the maximum steady state voltage
magnitude will be 110% of nominal voltage. ….
… Short-time variations (of several minutes duration) within 5% of the intended values shall be
considered in the design of plant by Code Participants….”
And section S3.2.5.3 on generator response to disturbances in the power system has:
“…connection point to drop to zero for up to 0.175 seconds in any one phase or combination
of phases, followed by a period of ten seconds where voltage may vary in the range 80110%.”
The voltage band from 90 % to 110 % of nominal voltage (Un) is already implemented as default
on European inverters. No change is necessary if these inverters are deployed.
FRT capability in Europe is not requested on the Low Voltage (LV) grid, but only on higher grid
voltage levels, however many inverters are prepared for this feature, since they may be employed in
PV systems connected to the MV grid. The Kenyan requirement for FRT for 0.175s duration is slightly
higher than in Europe (0.150s).
14
It should be clarified whether FRT will be requested also for generators connected to the LV grid.
Reactive power capability
According to Section S3.2.5.1 of the Grid Code power factor (PF) limits are 0.85 inductive and 0.95
capacitive.
Modern inverters can typically deliver PF >= 0.95 (Pn<= 13.8 kVA) or PF >= 0.90 (Pn<= 13.8kVA). This
is a sub band of the code requirement. It is only minor constraint, not impeding application of PV
technology. Typically most systems are set to a PF of 1.
Voltage quality (harmonics, dips, swells, phase unbalance)
These topics are stated in Code section S3.1.6. The Grid Code refers to requirements according to
the IEC 61000 standard series. This is an internationally recognized standard.
A2.3
Sample interconnection diagrams
The following figures show sample interconnection diagram for distributed generation.
15
Figure 3: Sample interconnection diagram for distributed generation
16
Figure 4: Typical single-line diagram for the protection of a synchronous generator
17
Figure 5: Typical single-line diagram for the protection of an induction generator
18
Figure 6: Typical single-line diagram for the protection on an inverter
19
References
A3
References

Aanesen, Krister; Heck, Stephan and Dickon Pinner, Solar Power: Darkest Before Dawn,
May 2012

Bazilian, Morgan; Onyeji, Ijeoma; Liebreich, Michael; MacGill, Ian; Chase, Jennifer;
Shah, Jigar; Gielen, Dolf; Arent, Doug, Landfear, Doug and Shi Zhengrong, Reconsidering the Economics of Photovoltaic Power, 2012

California Public Utilities Commission, Update on Determining the Costs and Benefits of
California’s Net Metering Program as Required by Assembly Bill 58, 2005

Cornell University ILR School and BW Research Partnership, National Solar Jobs Census
2012: A Review of the US Solar Workforce, a report for The Solar Foundation, November
2012

Curran, Patrick and Gerrit W. Clarke, Review of Net Metering Practices, Camco Clean
Energy report to the Electricity Control Board of Namibia, December 2012

Economic Consulting Associates and Ramboll, Renewable Energy Resource Potential in
Kenya. Final report submitted to the Ministry of Energy and the Energy Regulatory
Commission under the World Bank-supported Technical and Economic Study for the
Development of Small-Scale Grid Connected Renewable Energy in Kenya, August 2012

Edison Electric Institute, Disruptive Challenges: Financial Implications and Strategic
Responses to a Changing Retail Electric Business, January 2013

Energy and Environmental Economics, Inc, Net energy metering (NEM) cost
effectiveness evaluation. Study for the California Public Utilities Commission, 2010

Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ), Grid Connection of
Solar PV: Technical and Economical Assessment of Net-Metering in Kenya, December
2011

GTZ, Bernard Mutiso Osawa, Country Chapter: Kenya. In Renewable Energies in East
Africa Regional Report, 2009.

GTZ, Policy and regulatory framework conditions for small hydropower in Sub-Saharan
Africa, discussion paper, 2010

Hankins, Mark, Solar Energy Market Potentials in East Africa. Presentation for the
Renewable Energy Project Development Programme East Africa, November 2009

IRENA, Renewable Energy Technologies: Cost Analysis Series, Solar Photovoltaics, June
2012

IRENA, Renewable Power Generation Costs in 2012: An Overview, 2013

Kenya Power, Annual Report and Financial Statements, Financial year ended 30 June
2012
20
References

Kenya Ministry of Energy and Petroleum, 5,000+ MW by 2016: Power to Transform,
Investment Prospectus 2013 – 2016, September 2013.

Kenya Ministry of Energy, Kenya Cost of Service Study (COSS), January 2013

Kenya Ministry of Energy, Electricity Sub-Sector Medium-Term Plan 2012-2016 (MTP),
February 2012

Kenya Ministry of Energy, National Energy Policy Final Draft, March 2013.

Kenya Ministry of Energy, Updated Least Cost Power Development Plan 2011-2013
(LCPDP), March 2011

Kenya Ministry of Energy and Ministry of Foreign Affairs Finland, 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, November 2008

Kost, Christoph; Schlegl, Thomas; Nold, Sebastian and Johannes Mayer, Levelized Cost
of Electricity: Renewable Energies, 20 May 2012 edition, Fraunhofer Institut for Solar
Energy Systems (ISE), May 2012

Missaoui, Rafik and Sami Marrouki, Etude sur les mécanismes innovants de
financement des projets d’énergie renouvelable en Afrique du Nord. Rapport final pour
l’Economic Commission of Africa, December 2012.

NREL, Photovoltaic (PV) Pricing Trends: Historical, Recent, and Near-Term Projections,
November 2012

Nyang, Frederick, ERC Media Briefing: Review of the Retail Electricity Tariffs for the
Tariff Control Period 2013/2014 – 2015/2016, Energy Regulatory Commission
presentation, November 2013

Ondraczek, Janosch, The Sun Rises in the East (of Africa): the Development and Status of
the Solar Energy Markets in Kenya and Tanzania, University of Hamburg, 2011

Renewable Energy Policy Network for the 21st Century (REN21), Renewables 2012
Global Status Report, 2012

REN21, Renewables 2013: Global Status Report, 2013

Solar America Board for Codes and Standards (SABCS), Jason B. Keyes Joseph, F.
Wiedman, Interstate Renewable Energy Council, A Generalized Approach to Assessing
the Rate Impacts of Net Energy Metering, January 2012

Weissman, Steven and Nathaniel Johnson, The Statewide Benefits of Net-Metering in
California & the Consequences of Changes to the Program. University of California,
Centre for Law, Energy and the Environment, February 2012
Country-specific references are provided in Annex A7.
21
Contribution to renewable energy targets and economic
development
A4
Contribution to renewable energy targets and
economic development
As part of the assessment of the policy rationale for and objectives of a net metering programme in
Kenya, a brief analysis of the potential NEM contribution to meeting national renewable energy
targets and examples from other countries of ways in which it could have economic development
benefits is provided.
Net metering contribution to renewable energy targets
Table 11 below provides the draft National Energy Policy targets per technology type. Geothermal
and household biogas for cooking and lighting are excluded as being of less relevance for net
metering. However, there is one 4 MW geothermal heat and power generator for own consumption
at a flower farm at Lake Naivasha that is an example of a geothermal project that may in theory have
a surplus available for export from time to time. Similarly, there is one operational 150 kWel biogas
power plant in Kilifi designed for on-site consumption that is run below maximum capacity due to
lack of an arrangement for grid export of surplus units – a potential net metering candidate.
Table 11 Renewable energy targets
Technology type Short-term target
Biomass, waste
and
cogeneration4
Mid-term target
Long-term target
(2013-2017)
(2013-2022)
(2013-2030)
At least 50 MW of electricity
using municipal or industrial
solid waste.
At least 100 MW of electricity At least 300 MW of
using municipal or industrial
electricity using municipal
solid waste.
or industrial solid waste.
At least 200 MW of coAt least 800 MW of cogeneration via PPP
generation from bagasse and
arrangements from bagasse and agro-residues.
agro-residues.
Solar5
At least 1,200 MW of cogeneration from bagasse
and agro-residues.
At least 100,000 units of solar
PV home solar systems.
At least 200,000 units of solar At least 300,000 units of
PV home systems.
solar PV home systems.
At least 100 MW electricity
from solar.
At least 200 MW electricity
from solar.
At least 500 MW
electricity from solar.
Wind6
At least 1,000 MW wind energy 2,000 MW wind energy
generation capacity.
3,000 MW wind energy
Small hydro7
Small, mini, micro- and picoSmall, mini, micro- and picohydropower capacities totalling hydropower capacities
50 MW from various sites.
totalling 100 MW from
various sites.
Small, mini, micro- and
pico-hydropower
capacities totalling 300
MW from various sites.
4
Gok (2013) National Energy Policy Final Draft, Ministry of Energy, Republic of Kenya, Section 3.10.4
5
Section 3.7.4
6
Section 3.8.3
7
Section 3.3.2.4
22
development
These ambitious targets, and the aforementioned policy goal of 70% clean or renewable energy, can
be met by the implementation of a similarly ambitious suite of policy measures, of which net
metering could be an integral component. For example, some of the above targets, most notably for
wind and small hydro, may be significantly but not entirely met under a power purchase or Feed-inTariff regime. In the case of solar, net metering could make an important contribution.
For wind, the February 2012 draft of the Electricity Sub-Sector Medium-Term Plan indicates 380.4
MW of committed wind projects by 2016,8 the 2011 Updated Least Cost Power Development Plan
foresees 2,036 MW in the base case scenario by 20309 and the list of approved wind projects under
the Feed-in-Tariff (FIT) had reached 1,911 MW by April 2012 around the time when further wind
application were put on hold. In none of these scenarios would the target be achieved. While based
on experience in other countries wind systems under net metering would likely only make a very
minor contribution to the target, such installations may also pose less of a grid integration challenge.
In terms of small hydro, a 2006 Ministry of Energy study indicated that a theoretical potential of
3,000 MW of small hydropower sites (≤10 MW) may be available. However, the technical and
economic potential is likely much lower10 and probably more in the range of 200 – 1,000 MW,11 12
with an upper limit of 600 MW a more realistic figure taken from the 260 potential sites that have
been identified13 also due to degradation of hydrological resources. Exploitation of half of the upper
limit of potential sites by 2030 would result in Kenya achieving its national energy policy target. As of
April 2012, 102 MW of small hydro had been approved under the FIT according to the Energy
Regulatory Commission records. Two Kenya Tea Development Agency (KTDA) Power Ltd 5 MW small
hydro sites are under construction and many more are at the feasibility or development stage. It is
therefore probable that the 2022 installed capacity target of 100 MW will be met under a power
purchase or FIT mechanism.
However, the policy targets include contributions from mini, micro and pico-hydro. These are usually
defined respectively as generators with a capacity between 100 kW-1,000 kW, 5-100 kW and 0-5
kW. Pico hydro sites alone could possibly reach 3 MW in total. With the 500 kW FIT lower limit,
many mini-hydro and all micro and pico-size projects are excluded from participating in national grid
supply whereas Kengen operates two ~400 kW legacy hydro projects (Mesco and Sosiani) feeding
the grid. There are also at least six private mini or pico-hydro projects under 100 kW electrifying a
community mini-grid and the 400 kW Tenwek missionary hospital project for internal
consumption,14 examples of the types of projects that may be further expanded or replicated under
8
GoK (2012) Electricity Sub-Sector Medium Term Plan (2012-2016) – February 2012 draft for circulation.
9
GoK, Ministry of Energy (March 2011) Updated Least Cost Power Development Plan: study period 2011-2013, p. 139.
10 GTZ. 2010. Policy and regulatory framework conditions for small hydro power in Sub-Saharan Africa. Discussion
paper, p. 30.
11
Gok, LCPDP, p. 50.
Bernard Mutiso Osawa. 2009. Country Chapter: Kenya. In Renewable Energies in East Africa Regional Report,
GTZ, p. 47.
12
Ministry of Energy Kenya, Ministry of Foreign Affairs Finland. 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. November 2008, p. 25.
13
Economic Consulting Associates and Ramboll. August 2012. Renewable Energy Resource Potential in Kenya. Final
report submitted to the Ministry of Energy and the Energy Regulatory Commission under the World Banksupported Technical and Economic Study for the Development of Small-Scale Grid Connected Renewable
Energy in Kenya, p. 25.
14
23
development
net metering with economic and social benefits. Furthermore, even if approved under the FIT such
small projects after often not commercially viable with the offered tariff and are better suited for
local consumption with the possibility of grid offtake of any surplus. Mini, micro and pico-hydro
under net metering could also make a contribution to the regional balance of electricity supply since
after the Mt Kenya region the west of the country, where there are fewer existing and planned
generation facilities, transmission bottlenecks and reported voltage stability problems, has the
greatest potential. However, a number of the sites are far from the main grid and this may reduce
their potential contribution in the short to medium-term.
The operational KTDA Imenti small hydro project located north of Mt Kenya may be a good example
of where net metering could play a role. The Imenti run-of-river project has an installed capacity of
920 kW (1 MW turbine) and was primarily designed for own consumption (tea factory supply) with
an average internal demand of ~600 kW (600 kVA), meaning approximately 320 kW is available on a
regular basis for grid-export. The project size was determined by economic optimization based on
the power potential of the river at the site and possibly also to help meet factory peak load, which
can exceed 1.3 MVA. Following negotiations, a power purchase agreement was signed for supply of
the surplus to the main grid. This was agreed outside of the FIT regime due mostly to the surplus
capacity being less than the minimum allowed and also due to variations in the excess power
available for export.15 If the project had come under net metering, it would have likely reduced
transactions costs although the impact on utility revenue loss may have been greater since the tariff
agreed was lower than the utility avoided or retail electricity cost. KTDA alone has a number of tea
factory sites with similar circumstances. Another example is a 58 kW small hydro project near Embu
town (south of Mt Kenya) that is part of a municipal irrigation scheme. The project currently
generates surplus power that could be fed into the grid but is dissipated in a heat sink due to lack of
a net metering arrangement.
With regards to solar, neither the Least Cost Power Development Plan nor the Electricity Sub-Sector
Medium Term Plan includes any solar power projects. The pipeline of FIT projects as of April 2012
indicates only 2 MWp approved, all at off-grid rural stations. More recently a number of large-scale,
grid-connected solar PV proposals have been tabled exceeding 200 MWp in total, whereas the 2012
version of the FIT policy has an initial aggregate cap of 100 MWp. As the cap may be increased
incrementally as new solar capacity comes online it is likely that the 2030 solar PV target of 500
MWp could be met by 2030 without net metering.
Nevertheless, solar PV under net metering could also make a relevant contribution especially as the
FIT policy has a lower size limit of 500 kW, which excludes the participation of smaller customers in
meeting energy supply, a policy objective stated by a number of countries who have adopted net
metering. It was estimated as early as 2004 that more than 4 MWp of small solar PV systems are
installed in Kenya mainly comprised of small household systems of 14-120 Wp and institutional and
telecommunication systems of 2-5 kW16 and that this capacity is growing at a rate of 1-1.3 MWp per
annum.17 This means that 13-16 MWp of small solar PV systems may have been installed
countrywide by the end 2013, in addition to the approximately 400 kWp in diesel-solar PV hybrid
mini-grid power stations operated by the Kenya Power & Lighting Company. Any net metering policy
could be expected to increase the rate of uptake and may in parallel support the development of a
15
KTDA Power Ltd. Personal communication, 28 March 2012.
Osawa, Bernard Mutiso. 2009. Country Chapter: Kenya. In Renewable Energies in East Africa Regional Report,
GTZ, p. 47.
16
Hankins, Mark. Solar Energy Market Potentials in East Africa. Presentation for the Renewable Energy Project
Development Programme East Africa. 20 November 2009.
17
24
development
local solar industry as has been experienced in other countries. As of 2011, 300,000 solar home
systems may have already been installed in Kenya.18 This figure likely excludes the 945 solar PV
systems installed in primary and secondary schools, dispensaries, health and administrative centres
as at 2012 under a Ministry of Energy programme for electrification of remote institutions.19
Presumably the draft energy policy targets an additional 300,000 home installations by 2030, which
could conceivably be achieved in the absence of any net metering regime given the historic
precedence.
Lastly, in terms of the 70% renewable energy target, as at 30 June 2012 renewable power plants of
all sizes (including large hydro) made up approximately 61% of installed power capacity and 66% of
generation.20 Since 2005, this has ranged from 63-69% for installed capacity and 55-75% depending
on hydrology for generation.21 Looking forward, according to the base case in the 2011 Least Cost
Power Development Plan, renewable energy installed capacity in 2031 will be 49% of the grid mix
(including 2,000 MW of hydro import from Ethiopia), against 32% from fossil fuel sources and 19%
from nuclear. As for generation, renewables are expected to contribute 63% (including 43% from
geothermal) with 10% coming from fossil fuel sources and 27% from nuclear by 2031. In neither case
would the 70% target be achieved, although if nuclear is considered as a “clean” source of power
then the target would be nearly met or exceeded. However, regardless of how the technology is
categorized, there is some likelihood that nuclear power development plans may be delayed (the
first 1,000 MW are planned to be online by 2022, meaning construction should start by 2016-18) and
the resultant shortfall would need to be bridged. It is not known if this would be by renewables,
conventional sources or a combination of the two.
The above figures do not take into consideration the contribution of embedded generation from
small-scale (≤ 10 MW) renewable energy sources, which could be expected to increase the
renewable share by a few hundred MW or 2-4% by 2031, still not reaching the 70% target. Any
further contribution from small-scale decentralized renewable energy systems under net metering
would be in line with the draft national energy policy objectives.
Thus, the draft national energy policy renewable energy targets provide some justification for net
metering in Kenya.
Net metering contribution to economic development, technology innovation,
local industry and job creation
Of the 11 countries studied, five consider economic development and related aspects such as job
creation as a prime motivation for the implementation of net metering. While information on the
actual contribution is scarce and listed achievements may not be solely attributable to net metering
per se, the following findings give some examples of economic benefits:22
Ondraczek, Janosch. 2011. The Sun Rises in the East (of Africa): the Development and Status of the Solar Energy
Markets in Kenya and Tanzania, University of Hamburg, p. 1.
18
19
Gok (2013) National Energy Policy Final Draft, Ministry of Energy, Republic of Kenya, p. 67.
Kenya Power & Lighting Company Ltd. Annual Report and Financial Statements for the financial year ended 30 June
2012, pp. 104-105.
20
21
Consultant’s own analysis based on Kenya Power annual reports.
Unless otherwise referenced, the findings are taken from the country overviews, where references for each are
available.
22
25
development
In Sri Lanka, due to potential national and regional demand from net metering and other
programmes, the Lanka Electricity Company, the smaller of the two Sri Lankan utilities, has
established a domestic high-tech energy meter manufacturing facility with an annual production
capacity of 500,000 units. The factory has the capability to make both electromechanical and
electronic meters of single or three-phase and can produce poly-phase meters, smart meters, prepaid meters, automatic or remote meter reader-enabled meters and Broadband Power Line (BPL)
meters. This has also helped the utility to diversify its business interests and revenue streams.
In Tunisia, with 739 customers and approximately 1.3 MWp of solar PV under net metering as of
February 2012, the programme had facilitated the emergence of 30 new solar PV installation
companies. The success is partially due to investment subsidies provided by the government.
Furthermore, the market potential with an initial target of 15 MWp led to the establishment of the
first unit of a solar PV module manufacturing facility with an annual capacity of 25 MWp.
In the United States, the more than 3,500 MW of decentralized capacity mostly under net metering
across more than 300,000 customers as of December 2012 gives an indication the level of demand
from distributed solar PV generation that helps support almost 120,000 “solar worker” jobs in the
country with a November 2012 12-month employment growth rate of 13.2% against 2.3% for the
American economy as a whole.23 Of these jobs, 26,000 are in California, where it is noted that the
success in generating employment is due to the diversity of the positions available in the industry:
design, manufacturing, sales and marketing, installation and maintenance. As biomass and biogas
were only more recently (2011) included as eligible project types in California, further economic
benefits are expected to accrue in the farming sector where agricultural residues can be used to
generate power for own consumption and grid export under net metering.24 The job count does not
include indirect employment such as financial service providers and government positions to
oversee and support the sector. While there are other drivers behind the industry and job growth
(such as funding incentives), it is arguable that net metering mechanisms are playing an important
role.
Other benefits in California in particular include the availability of peak-coincident solar energy and
enhanced resilience to unexpected supply interruptions, both of which have positive economic
impacts. On the other hand, distributed solar PV including under net metering has played a role in
the application denial of at least one proposed 100 MW natural gas power plant, which may have
had negative financial repercussions for the company involved.
There are undoubtedly further examples. The small selection provided here nevertheless shows why
a number of countries took national economic considerations into account when adopting net
metering.
The Solar Foundation website. National Solar Jobs Census, November 2012.
http://thesolarfoundation.org/research/national-solar-jobs-census-2012 - accessed 25 August 2013.
23
Weissman, Steven and Nathaniel Johnson. February 2012. The Statewide Benefits of Net-Metering in California &
the Consequences of Changes to the Program. University of California, Centre for Law, Energy and the Environment,
p. 7. http://www.law.berkeley.edu/files/The_Statewide_Benefits_of_NetMetering_in_CA_Weissman_and_Johnson.pdf.
24
26
A5
A5.1
Tariff levels from July 2008 to November 2013
Table 12 Electricity tariffs (2008-2013, excluding December 2013)
Type of
consumer
Type of
connection
Min/Max
consumption
Billing method
Other costs
Relevant
component*25
(KES/kWh)
Fixed charge: 120
KES/month
DC Domestic
SC
Small
Commercial
240 or 415V
240 or 415V
Maximum
15 MWh/mo
Maximum
15 MWh/mo
Unit cost
depending on
consumption: KES
8.10/kWh (<1500
kWh/month) and
18.57 KES/kWh
(>1500
kWh/month)
Fixed charge: 120
KES/month
Unit cost: 8.96
KES/kWh
Fixed charge: 800
KES/month
CI1
Unit cost: 5.75
KES/kWh
415V, 3Ø
Demand charge:
600 KES/kVA
Fixed charge: 2500
KES/month
Commercial
CI2
& Industrial
11 kV
Minimum
15 MWh/mo
Unit cost: 4.73
KES/kWh
13.37 to 22.8
All categories of
consumers
additionally pay the 14.23
following concepts
(all proportional to
energy
consumption):
Fuel cost
adjustment:
seasonal, average
5.27 KES/kWh
11.02
FOREX and inflation
adjustments
ERC and REP levies
VAT
10.00
Demand charge:
400 KES/kVA
Fixed charge: 2900
KES/month
CI3
33 kV
Unit cost: 4.49
KES/kWh
9.76
Demand charge:
200 KES/kVA
At this stage and for simplicity purposes we assume the relevant component of electricity price (i.e.
components that would be offset by net metering) are only the unit cost and fuel cost adjustment. Fixed charge
and demand charge would continue to be paid for the benefit of having a grid connection.
25
27
Type of
consumer
Type of
connection
Min/Max
consumption
Billing method
Other costs
Relevant
component*25
(KES/kWh)
Fixed charge: 4200
KES/month
CI4
66 kV
Unit cost: 4.25
KES/kWh
9.52
Demand charge:
170 KES/kVA
Fixed charge:
11000 KES/month
CI5
132 kV
Unit cost: 4.10
KES/kWh
9.37
Demand charge:
170 KES/kVA
A5.2
Projection of electricity tariffs
Electricity tariff projections are fundamental to assess the benefits and costs of NEM for both
consumers and the utility. This study uses the projections of the COSS 2013 and a simplified
projection used by the RTAP financing facility in the evaluation of their RE projects.
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
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.
This study uses the simplified tariff projection for most of the analysis. The COSS projections are
used as a cost reflective benchmark in the economic assessment of section of Volume 1.
Annex A1 above provides an assessment of the implications of the 2013 Schedule of Tariffs for net
metering.
Simplified tariff projection
A simplified and possibly more realistic tariff projection forecasts a price increase 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 7
presents this simplified tariff projection for CI1 customers.
28
Figure 7 Simplified tariff projections for CI1 customers
COSS projections
The tariff schedule proposed in the COSS is based on the revenue requirements of the utility. Some
important points of this COSS:

Load growth assumed is the base case MTP for 2011/12 to 2015/16 and then the low
scenario from the LCPDP.

The same demand forecast is assumed over 2012-2022, but two different generation
scenarios are considered. Scenario A has 2,226 MW of new capacity at a cost of KSh
428.8 b ($4,930 m) while Scenario B (with less hydro and more wind and thermal) has
2,917 MW at a cost of KSh 867.8 b ($9,975 m) (pg S-6).These figures assume that the
committed projects 1,805 MW (pg 7-2) are also implemented.

2011 LCPDP (base case) has much bigger investments in prospect - over 6,700 MW of
new capacity between 2012 and 2022. LRMC at the ‘bus’ of 11.86 c/kWh and 14.82
c/kWh ‘sale’.

Scenario A has been adopted in this analysis. LRMCs are 9.85 KSh/kWh for generation,
3.66 KSh/kWh for transmission and 5.33 KSh/kWh for distribution (11.3 + 4.2 + 6.1 =
21.7 c/kWh with rounding). The T & D LRMC figures are high in relation to generation
costs. This is because of the need for grid reinforcement and extension and
underinvestment in distribution in the past.

Financial considerations dictate that the tariffs need not / should not increase
immediately to the LRMC values. The recommended average tariffs (pg S-13) are 14.13
KSh/kWh (16.2 c/kWh) in 2014, 16.23 KSh/kWh (18.7 c/kWh) in 2018 and 16.94
KSh/kWh (19.5 c/kWh) in 2022.

The LRMC approach is nonetheless important in defining relative tariffs to ensure an
economically efficient solution. This is not of course the only consideration in setting
29
the tariffs, but it is an important one. COS basically endorses the current structure of
tariffs (no change in the categories, but there are some amendments proposed in
response to large customers wanting to be connected at higher voltages to get lower
tariffs - see Section 12.2.2, pg 12-9).

The tariff increases recommended are given on pages S-20 and S-21 of the exec
summary, with supporting detail elsewhere in the report. For the purposes of the NM
case studies, the defined path of increases can be used to project forward the likely
tariffs for the particular customer category into which the NM case study falls, eg UNEP
has C12 tariffs.

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 8.
Figure 8 Proposed tariff increase for CI1 customers (COSS 2012)
30
A6
These proposed net metering application and implementation procedures are designed to be as
simple as possible while maintaining due process. They will need to reviewed and refined as
experience is gained in implementing net metering. The proposed approach is intended to give the
regulator and utility an idea of the likely administrative burden of the programme.
The proposed procedures for all project types and sizes are as follows:
Step 1
The applicant assesses their situation and takes the decision to apply for a net metering
arrangement. The applicant then reviews the net metering (NEM) application form, standard NEM
agreement and other relevant documents including any technical standards and metering
requirements that must be met to have a clear understanding of the requirements. The latest
versions of these documents will be available for download on the websites of the utility and the
regulatory. Hard copies will also be maintained in the office of the local utility distribution Area
Engineer.
After reviewing the documentation, the applicant then initiates contact with the respective utility
Area Engineer responsible for distribution in their locality to inform the Engineer of the intention to
apply for net metering and enquire as to any special restrictions for the local grid network. .
Step 2
The applicant, usually with the involvement of a qualified contractor, prepares a basic preliminary
system design based on the required technical parameters. The applicant then submits the required
documentation including a copy of the design diagram along with the application fee. While the
documentation will be submitted to the respective utility Area Engineer and with a copy to the
regulator, the application fee will be paid to the commercial services department within their
locality. The Area Engineer will liaise internally with other relevant utility departments, e.g. planning,
research and performance monitoring and commercial services and inform them of the application.
For the initial net metering applications is it anticipated that the regulator will play an active role to
help facilitate the process. Later the regulator can step back to its oversight role.
Step 3
The utility distribution Area Engineer will then perform a preliminary check whether the project is
eligible against the following criteria:.
1. Is the application documentation in order and properly completed?
2. Has the applicant paid the application fee to the customer service department?
3. Does the project use a renewable resource?
31
4. System capacity
a. Is the rated/installed capacity within the maximum limits, if any, allowed under the
NEM regulations?
b. Will the NEM generating facility exceed the contract demand of the existing contract
between the customer and the utility (not relevant for first time grid connections)?
c. Is the system designed primarily to meet average onsite demand?
d. Is the proposed NEM system better suited to the FIT policy?26
5. Local feeder capacity
a. Is the customer on a low-voltage connection?
b. Is the maximum system output not more than 75% of the feeder capacity or a portion
thereof if there is one or more other existing net metering customer or requesting a net
metering arrangement?
6. Is the applicant a customer in good standing with the utility – e.g. no outstanding bill
payments due (not relevant for first time grid connections)?
This preliminary check shall be completed within two weeks of the receipt of application.
Step 4
The utility distribution Area Engineer will share the applicant’s documentation and the outcomes of
preliminary assessment in step 3 above with an internal ‘Net Metering Assessment Team,’ to be
newly established and composed of one member of each of the central distribution, planning and
customer service departments. The team will assess net metering applications on an ongoing and
first-come, first-serve basis. Based on the documentation provided, the preliminary assessment and
other considerations that may be relevant, the team will give the initial approval for the project to
proceed or deny the application on the basis of specific reasons to be recorded. This decision will be
taken within one month of having received the preliminary findings. The initial decision will be
communicated to the utility Area Engineer as well as the applicant within one week.
In the case of rejection, the distribution utility will inform the applicant giving the reasons in writing.
A copy of completed application documentation as well as a record of the Net Metering Assessment
Team decision for each applicant will be provided to the Energy Regulatory Commission (ERC) on a
biannual basis for information and independent review of due process.
Step 5
In the case of a positive preliminary assessment, the applicant pays the standard site visit fee to the
utility’s commercial services department within their locality
Ideally the net metering capacity should be based on the minimum capacities provided for in the FiT Policy i.e.
not based on installed capacity but on capacity available to give to the grid. For instance if there is an installation
of 800kW which internally utilizes 700kW, then the balance 100kW will be connected to the grid on net metering
basis, but if the same installation of 800kW utilizes 250kW and the balance of 550kW should be considered under
FiT Policy.
26
32
Step 6
The relevant utility distribution Area Engineer27 conducts a site visit to view and access the premises
and identify specific protection and interconnection requirements (in line with the standard
technical requirements). The Area Engineer shall prepare a short report outlining the specific
equipment required, which will be shared with the applicant and the Net Metering Assessment
Team.
For certain projects, normally those whose maximum output exported to the grid at any one time
may be considerable, a more detailed system impact study may be required. This will be
communicated to the applicant, who shall bear the costs for any such in-depth study that will
normally be performed by an external expert.
Step 7
Upon receipt and acceptance of the interconnection report by the applicant and the Net Metering
Assessment Team, the utility and the applicant will enter into a simple Net Metering Agreement. A
condition precedent of the entry into force of the agreement shall be that the system
interconnection is tested, commissioned and signed off on in the presence of a utility representative.
Once the agreement is signed it shall be shared with the regulator.
Step 8
The applicant shall then pay for, procure and have a qualified third party install the necessary
interconnection equipment in accordance with the technical standards and any additional
specifications as per the Area Engineer’s interconnection report.
Step 9
The applicant or the applicant’s contractor then gives the utility a notice of readiness in order for the
Area Engineer or other utility representative to plan for the final site visit to test, commission and
certify the system. With this notice the applicant pays a fee to the commercial service department
that will be used to facilitate the site visit. The Area Engineer will then inform the Net Metering
Assessment Team of the site visit date mutually agreed with the applicant and invite their
participation.
Step 10
The Area Engineer or other utility representative conducts a site visit to witnesses the operation and
commissioning of the system. The successful integration is certified by the utility representative and
the Interconnection Agreement enters into force. In case the utility disapproves of the system
connection the applicant will need to recheck the system installation and the equipment. In the case
of successful integration, a copy of the certification/commissioning report is sent to the regulator.
27
Or a representative from the same department
33
Step 11
In addition to the normal meter readings, the Area Engineer or other utility representative must
regularly record the export meter readings, either manually or if these are automatically
transmitted. On a monthly basis a copy of all records shall be transmitted to the Net Metering
Assessment Team and other relevant utility departments (e.g. billing). The billing department will
perform the necessary calculation to assess how much of the customer’s monthly consumption can
be offset with NEM credits exported at the discounted rate or if there is a surplus to carry forward to
the next billing period. This information will be transparently indicated on the net metering
customer’s bill or in a separate monthly information note provided by the utility.
Step 12
The recorded data for individual net metering customers will be aggregated and analysed by the
utility and shared with the regulator on an annual basis. The net metering customer is also expected
to record basic system performance data where available and provide this to the regulator at the
end of each calendar year.
Notes

This approach assumes that the interconnection equipment procurement and
installation will be undertaken by the qualified third-party contractor and not the utility.

In some countries there is automatic approval of micro net metering systems usually up
to 10, 20 or 30 kW as long as equipment and installation meets agreed technical
standards. In these cases the requirement for a site visit and site-specific assessment
are waived to speed up the process and reduce the burden on utility personnel. This is
not recommended for phase I net metering implementation or at least for the first few
systems installed in Kenya due to the need to first gain experience with small-scale
embedded generators but should be considered in the future as practical experience is
gained.

In Sri Lanka, Tunisia and other countries, the equipment installation companies are
responsible for liaising with the distribution utility for system application, approval and
implementation. The installers are the interface between the customer and the utility
and must provide the customer with guidance on application and administrative steps.
As these companies are “pre-approved” by the utility or regulator, this approach helps
to facilitate the process and ensure technical standards are met.
34
Figure 9 Flow diagram of proposed net metering application and approval process
START
Obtain applica on
documents for KPLC or ERC
website or u lity office.
Contact KPLC Area Engineer
for ini al discussion
Step 1
Site visit conducted. Short
report prepared & shared
with NEM applicant and
NEM assessment team
Submit applica on
documents, preliminary
design & applica on fee to
u lity company. For the first
applica ons a copy should be
sent to the regulator
NEM applica on documents
shared with other relevant
KPLC departments
KPLC Area Engineer
representa ve performs
preliminary check
Step 2
Step 3
KPLC Area Engineer
representa ve shares
outcomes to 'Net metering
assessment team'
Approval?
Poten al NEM customer pays
site visit fee
Y
Step 6
Step 5
Step 4
N
END
Simple Interconnec on
agreement
Once signed it is shared with
regulator
Step 7
Recorded data will be
aggregated, analyzed by
U lity and shared with
regulator annually
END
Third party installs
necessary
interconnec on
equipment
Step 8
Step 9
Step 10
Y
If integra on is
successful, copy of
cer ficate sent to
regulator
Area Engineer or U lity
rep to record export
meter readings
Step 12
System Verifica on through site
visit
U lity is given no ce
of readiness for final
site visit. Fee is paid
Step 11
Approval?
N
N
Recheck
Provide reasons
END - N/A for
NEM
Y
To step 9
35
A7
A7.1
United States of America
In the United States of America (USA or US) net metering policies are currently implemented at the
state level. The USA was the first country in the world to test the concept of net metering with small
residential solar PV and wind systems starting in 1983. Although formal net metering policies have
existed in a number of states beginning with California’s 1995 pilot programme, recent impetus was
provided with the 2005 federal Energy Policy Act, whereby the Public Utility Regulatory Policies Act
(PURPA) was modified to require state public utility commissions to “consider” standards for net
metering and interconnection.
As of January 2013, 46 states, the District of Columbia and four of the US overseas territories (Puerto
Rico, Guam, Virgin Islands and American Samoa) have policies to encourage net metering or utilities
with voluntary net metering programmes. Most programmes allow customers to sell excess
electricity generated to the utility a price greater than the avoided variable cost.28 In California for
example the exported generation is either credited at the full retail rate or at a time-of-use-rate,
with optional payment for net export after each 12-month period, to help incentivize net metering.
Net metering is by far the most common distributed generation billing mechanism in the US. There
are over 300,000 net metering customers with over 3,500 MW of solar PV installed among other
technologies. While the majority of these were in the residential category, there were also at least
30,000 non-residential net metering customers with system sizes of 100 kW and above representing
at approximately 1,600 MW installed as of January 2012. In the early years non-residential
customers were predominant, so the current status signals an important shift, possibly due to a
combination of (a) the 2005 Energy Policy Act, (b) declining solar PV prices, (c) the cumulative impact
of financial incentives in certain states such as California and (d) growing customer interest in “going
green”.
California is the state leader in net metering and solar PV systems and has important incentive
schemes to help achieve its 2009 renewable energy policy of 33% by 2020. The support for
renewable energy, including via distributed generation and net metering is based on the following
rationale taken from various policy and regulatory documents:

Meet greenhouse gas (GHG) emissions reductions goals

Support the move toward a cleaner energy economy overall

Continue California’s leadership position as a clean technology innovator

Provide energy security and independence

Help in meeting or shaving peak load (in California peak load is between 11:00 – 18:00
and is highest in the summer, when solar PV generation is also high)
North Carolina State University. Database for State Incentives for Renewables and Efficiency,
www.dsireusa.org http://www.dsireusa.org/summarytables/rrpre.cfm - accessed 10 August 2013.
28
36

Leverage private and federal funding for California

Promote customer investment in distributed generation

Continue to bring state and local environmental benefits

Promote job development and economic growth
In the USA distributed generation including under net metering has also been taken into account in
long-term utility resource planning and has played a role in the application denial of at least one
proposed 100 MW natural gas power plant.
Country
Size
9,147,420 sq km
Population
313,900,000
GDP per capita
USD 49,965 (2012)
GDP - composition by
sector
Agriculture: 1.1%
29
Industry: 19.2%
Services: 79.7% (2012 est.)
Main industries
Highly diversified, world leading, high-technology innovator, second largest
industrial output in world; petroleum, steel, motor vehicles, aerospace,
telecommunications, chemicals, electronics, food processing, consumer goods,
lumber, mining
National power system information
30
Installed capacity
1,039,062 MW (2010)
Electricity access
99.7%
Consumption per capita
~13,394.00 kWh/year
Generation
4,106,000 GWh/year (2011)
31
32
33
World Bank. World Development Indicators website. GDP per capita (current USD).
http://data.worldbank.org/indicator/NY.GDP.PCAP.CD - accessed 18 August 2013.
29
EIA website. International Energy Statistics: Total Electricity Installed Capacity 2010.
http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=7 - accessed 19 August 2013.
30
International Energy Agency. World Energy Outlook 2012. Electrification rate, percentage of population:.
http://www.iea.org/weo/electricity.asp - accessed 19 August 2013 (In the absence of data on electrification rate,
99.7% is assumed).
31
World Bank. World Development Indicators 2013: States and Markets, p. 86.
http://data.worldbank.org/sites/default/files/wdi-2013-ch5.pdf
32
37
Grid mix
Technology
% of total capacity (2011)
Natural gas
25%
Coal
42%
Hydro
8%
Nuclear
19%
Other
Peak load
35
Summer peak: 782,469MW
34
6%
36
Winter peak: 648,190 MW
37
T&D losses
7%
Average retail electricity
price per customer
category
Tariff
USD/kWh (2011)
Residential
0.12 (KES 10.16)
Transport
0.11 (KES 9.11)
Commercial
0.10 (KES 8.89)
Industrial
0.069 (KES 5.93)
38
Energy Information Administration (EIA). September 2012. Annual Energy Review 2011, p. 224.
http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf
33
Energy Information Administration (EIA). September 2012. Annual Energy Review 2011, p. 222.
34
Wind, petroleum, wood, waste, geothermal, other gases, solar thermal and photovoltaic, batteries, chemicals,
hydrogen, pitch, purchased steam, sulfur, miscellaneous technologies, and non-renewable waste (municipal solid
waste from non-biogenic sources, and tire-derived fuels).
35
EIA website. Table 8.6.A. Non-coincident Peak Load by North American Electric Reliability Corporation
Assessment Area, extract from Form EIA-411 of the Coordinated Bulk Power Supply and Demand Program
Report. http://www.eia.gov/electricity/annual/html/epa_08_06_a.html - accessed 15 August 2013.
36
Energy Information Administration (EIA). September 2012. Annual Energy Review 2011.
37
Energy Information Administration (EIA). September 2012. Table 8.1 Average Retail Prices of Electricity,
Selected Years, 1960 – 2011. Annual Energy Review 2011, p. 255.
http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
38
38
Legal framework and key information 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56
Interstate Renewable Energy Council. September 2012. 2012 Annual Update & Trends Report.
www.irecusa.org/wp-content/.../IREC-Trends-Report-2012_091312.pdf
39
Keyes, Jason B. and Joseph F. Wiedman. A Generalized Approach to Assessing the Rate Impacts of Net Metering.
Solar America Board for Codes and Standards Report. Interstate Renewable Energy Council. January 2012.
40
State of California. November 2008. Executive Order S-14-08. http://gov38.ca.gov/index.php?/executiveorder/11072/ - accessed 15 August 2013.
41
State of California. 2011. California Renewable Energy Resources Act. http://info.sen.ca.gov/pub/1112/bill/sen/sb_0001-0050/sbx1_2_bill_20110412_chaptered.html
42
California Energy Commission. April 2013. Renewables Portfolio Standard Eligibility. 7th Edition.
http://www.energy.ca.gov/2013publications/CEC-300-2013-005/CEC-300-2013-005-ED7-CMF.pdf
43
California Public Utilities Commission. January 1996. Public Utilities Code Section 2821-2829.
http://www.leginfo.ca.gov/cgi-bin/displaycode?section=puc&group=02001-03000&file=2821-2829 - accessed 15
August 2013.
44
California Public Utilities Commission. September 2008. Public Utilities Code Section 2830.
http://www.leginfo.ca.gov/cgi-bin/displaycode?section=puc&group=02001-03000&file=2830 - accessed 15
August 2013.
45
State of California. September 2012. Senate Bill 594, Wolk. Energy: net energy metering.
http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0551-0600/sb_594_bill_20120927_chaptered.html - access 15
August 2013.
46
State of California. September 2012. Assembly Bill 2165, Hill. Net energy metering: eligible fuel cell customergenerators. http://www.leginfo.ca.gov/pub/11-12/bill/asm/ab_21512200/ab_2165_bill_20120927_chaptered.html - accessed 15 August 2013.
47
California Public Utilities Commission. May 2012. Electric Program Investment Charge. Decision 12-05-037 for
Rulemaking 11-10-003. http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/167664.pdf
48
North Carolina State University. California Net Metering Program Overview. Database for State Incentives
for Renewables and Efficiency,
http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=CA02R&re=0&ee=0 - accessed 10 August
2013.
49
State of California. October 2011. Senate Bill 489, Wolk. Electricity: net energy metering.
http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0451-0500/sb_489_bill_20111008_chaptered.html - accessed
15 August 2013.
50
State of California. 2006. Senate Bill 1, Murray. Electricity: solar energy: net energy metering.
http://www.energy.ca.gov/2009-SOPR-1/documents/sb_1_bill_20060821_chaptered.pdf - accessed 15 August
2013.
51
State of California. October 2009. Assembly Bill 920, Huffman. Solar and wind distributed generation.
http://www.leginfo.ca.gov/pub/09-10/bill/asm/ab_0901-0950/ab_920_bill_20091011_chaptered.pdf - accessed
15 August 2013.
52
State of California. February 2010. Assembly Bill 510, Skinner. Net energy metering.
http://www.leginfo.ca.gov/pub/09-10/bill/asm/ab_0501-0550/ab_510_bill_20100218_enrolled.pdf - accessed
15 August 2013.
53
State of California. September 2002. Assembly Bill 2228, McLeod. Public utilities: net energy metering.
http://leginfo.ca.gov/pub/01-02/bill/asm/ab_2201-2250/ab_2228_cfa_20020814_101154_sen_floor.html accessed 15 August 2013.
54
California Public Utilities Commission website. Renewable Energy Self-Generation Bill Credit Transfer
Program (RES-BCT). http://www.cpuc.ca.gov/PUC/energy/DistGen/RES-BCT.htm - accessed 20 August 2013.
55
California Public Utilities Commission website. Decision 11-06-016 of 9 June 2011: Decision adopting net
surplus compensation. http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/137431.pdf - accessed 19 August
2013.
56
39
Enabling legislation
Federal:

The Energy Policy Act (2005)

The Public Utility Regulatory Policies Act (2005 amendment)
California:
Effective date
Date of any revisions
Incentive schemes

California Public Utilities Code Section 2821-2829 (net metering, 1996)

Renewable Energy Executive Order S-14-08 (2008)

California Renewable Energy Resources Act (2011)

2005 (federal)

1995 (California’s first net metering programme)
In California the net metering rules have been amended approximately 15 times
since programme inception. Examples of amendments are as follows:

Assembly Bill 2228, McLeod. Public utilities: net energy metering (2002)

Senate Bill 1, Murray. Electricity: solar energy: net metering (2006)

California Public Utilities Code Section 2830 (2008)

Assembly Bill 920, Huffman. Solar and wind distributed generation (2009)

Assembly Bill 510, Skinner. Net energy metering (2010)

Senate Bill 489, Wolk. Electricity: net energy metering (2011)

California Public Utilities Commission. Decision adopting net surplus
compensation (2011)

Senate Bill 594, Wolk. Energy: net energy metering (2012)

Assembly Bill 2165, Hill. Net energy metering: eligible fuel cell customergenerators (2012)

With 46 states practicing net metering each has a range of specific or general
incentives for distributed generation from grid-connected renewable sources.
The federal government has no specific incentives to support net metering
although it does support distributed generation from renewable sources.

California as the state that has taken net metering the furthest gives an
example of some of the incentives that may be available via the California
57 58
Energy Commission or other federal, state and municipal institutions:
California Energy Commission website. http://www.energy.ca.gov/renewables/index.html - accessed 15
August 2013.
58 California Solar Initiative website. http://www.gosolarcalifornia.org/csi/index.php - accessed 15 August
2013.
57
40
Achievements

(i)
From 1998 to December 31, 2006, the Energy Commission's Emerging
Renewables Program funded grid-connected, solar/photovoltaic
electricity systems under 30 kilowatts on homes and businesses in the
investor-owned utilities' service areas, wind systems up to 50 kW in
size, fuel cells (using a renewable fuel), and solar thermal electric. The
California Public Utilities Commission (CPUC) funded larger selfgeneration projects for businesses.
(ii)
Since 2007, Go Solar California is a statewide campaign with the goal
of 3,000 MW of solar generating capacity and a budget of USD 3.35
billion. As part of this, the California Solar Initiative (CSI) incentive
program provides support for solar energy systems of less than 1 MW
to existing and new commercial, industrial, government, nonprofit,
and agricultural properties. The CSI has a budget of USD 2 billion over
10 years, and the goal is to reach 1,940 MW of installed solar capacity
by 2016. The related New Solar Homes Partnership is a USD 400
million program, offers incentives to encourage solar installations,
with high levels of energy efficiency, in the residential new
construction market for investor-owned electric utility service areas.
The goal of the NSHP is to install 400 MW of capacity by 2016.
(iii)
Both programmes provide rebates (cash back) to grid-connected
customers for every watt of solar PV they install on their homes,
businesses, schools, farms, government offices and non-profit
institutions under net metering. Customers must choose between (a)
a Performance Based Incentive (PBI) paid over five years per kWh or
(b) a Expected Performance Based Buydown (EPBB) paid upfront per
W installed. The rebate available declines over time as aggregate
capacity increase. Depending on the customer category the EPBB
ranges from USD 2.50 – 3.25/W down to USD 0.20 – 0.70/W as more
MW are installed. For the PBI the rebate ranges from USD 0.39 –
0.50/kWh down to 0.025 – 0.088/kWh.
(iv)
In addition, net metering customers are eligible for Renewable Energy
Credits (RECs) under the Renewable Portfolio Standards program,
although these automatically vest with the utility if the customer
decides to receive end-of-year payment for any surplus net
generation.
(v)
Furthermore, net metering customers only pay tariff surcharges, such
as the Department of Water Resources surcharge and the Public
59
Goods Charge, on their net rather than gross consumption.
As of December 2012, a reported 302,380 net-metered systems were installed
60
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, in 88% were residential systems in
California Public Utilities Commission website. Net energy metering (NEM).
http://www.cpuc.ca.gov/PUC/energy/DistGen/netmetering.htm - accessed 19 August 2013.
59
Cliburn, Jill K and Joe Bourg. Ratemaking, Solar Value and Solar Net Energy Metering – A Primer. A Cliburn and
Associates report for the Solar Electric Power Association. July 2013, p. 1.
60
41
2011 as opposed to 24% in 2010.
Challenges

At the end of 2011, nearly 220,000 solar PV installations were connected to the
61
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
62
2,400 MW installed. Roughly two-thirds of this as of January 2012 is installed
63
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
64
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.

In California if not elsewhere in the US, distributed generation much of which
under net metering, is taken into account in the need for generation capacity.
Utility long-term resource planning includes customer-sited generation based
65
on load forecast 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
66
viable alternative.

Another achievement at least in California includes the availability of peakcoincident solar energy to reduce power purchase from peaking plants and
67
enhanced resilience to unexpected supply interruptions.

Faced with increased distributed energy generation, from net metering
customers and IPPs, as well as energy efficiency measures, power utilities in
the US are being encouraged to plan for a future where it is not business as
usual. A January 2013 report entitled “Disruptive Challenges: Financial
Interstate Renewable Energy Council. September 2012. 2012 Annual Update & Trends Report.
www.irecusa.org/wp-content/.../IREC-Trends-Report-2012_091312.pdf
61
Edison Electric Institute. Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail
Electric Business. January 2013, p. 4.
62
63
Solar Electric Power Association. 2012 SEPA Utility Solar Rankings, p. 5. SEPA report 02-13. June 2013.
www.solarelectricpower.org/media/.../final-2012-top-10-report-v2.pdf.
64
Cliburn, Jill K and Joe Bourg. Ratemaking, Solar Value and Solar Net Energy Metering – A Primer. A Cliburn and
Associates report for the Solar Electric Power Association. July 2013, p. 13.
65
California Energy Commission. Final Commission Decision: Chula Vista Energy Upgrade Project Application for
Certification (07-AFC-04), San Diego County. June 2009, p. 32.
http://www.energy.ca.gov/sitingcases/chulavista/
66
Weissman, Steven and Nathaniel Johnson. February 2012. The Statewide Benefits of Net-Metering in California &
the Consequences of Changes to the Program. University of California, Centre for Law, Energy and the Environment,
p. 2.
67
42
Implications and Strategic Responses to a Changing Retail Electric Business”
outlines some of the concerns and recommends new approaches rather than
trying to forestall the inevitable. The report was commissioned by the Edison
Electric Institute, an industry association representing 70% of US power
utilities and with 80 international members.

Restrictions on net metering in US state policies are mostly driven by utility
concerns that lower utility bills for net metering customers will lead to higher
68
utility bills for other customers.

A number of cases in US states assessing the rate impacts of net metering have
shown different results, in part dependent on the assumption in the studies.

In three cases, two in California and one in New Mexico, proposals by utilities
to charge an extra fee for net metering or distributed generation customers
considered to not be paying full costs for their energy use were either (a)
rejected, (b) shown to be unjustified and dropped or (c) shown to be minimal –
e.g. USD 0.00011/kWh or a 0.1% impact for each percentage of [solar in this
case] contribution to utility peak demand, growing to USD 0.00064/kWh if
total net metering solar installed capacity would reach 2,550 MW by 2017.
The third study noted that incremental billing costs may contribute as much of
27% of the cost of net metering to other ratepayers.

In a case that went the opposite direction in Virginia, a substantial standby
69
charge was imposed on net metering systems between 10-20 kW. As another
example, in March 2013 the utility Arizona Public Service Company was
allowed by the regulator to implement a new charge to recover a portion of
the fixed costs due to the impact of reduced electricity sales because of
70
customer renewable energy systems and energy efficiency measures.
Overview of net metering programme design characteristics 71
Item
Technology types
permitted
In California:

All technology types being solar thermal electric, solar photovoltaic, landfill gas,
wind, biomass, geothermal electric, fuel cells using renewable fuels, municipal
solid waste, biogas, small hydro, tidal energy, wave energy and ocean thermal.

Initially (1995) only solar and wind were eligible, then biogas and fuels cells
68
The examples cited are taken from (a) Cliburn, Jill K and Joe Bourg. Ratemaking, Solar Value and Solar Net
Energy Metering – A Primer. A Cliburn and Associates report for the Solar Electric Power Association. July 2013,
p. 12, and (b) Freeing the Grid online blog. In Focus 2012: Assessing The Costs And Benefits Of Net Metering The
Right Way http://freeingthegrid.org/#blog/in-focus-2012-assessing-the-costs-and-benefits-of-net-metering-theright-way/ - accessed 19 August 2013.
69
Mulkern, Anne C. 2 April 2013. Utilities challenge net metering as solar power expands in Calif. Climate Wire
website: http://www.eenews.net/stories/1059978731 - accessed 18 September 2013.
70
Where USA-wide information can be summarized to a sufficient level of detail, this is provided. Otherwise the
California net metering example is used.
71
43
(2003) and others were added over time.
Eligible customer
categories
Maximum system size
Aggregate system cap

Depends on individual state-level policies. Generally in all cases residential and
small commercial are eligible. In California, all state and municipal-level
utilities are obliged to offer net metering to customers in the following
categories. Only one municipal utility is exempt due to specific circumstances.
(i)
Commercial
(ii)
Industrial
(iii)
Agricultural
(iv)
Residential
(v)
Non-profit, including local government

However, in California customers connected to distribution voltages where
there are secondary networks (parallel networks used to improve reliability) in
dense urban areas – in this case San Francisco and Oakland – are not eligible
for net metering based on concerns over safety and system impacts due to the
nature of the protection equipment deployed.

Most states have maximum individual limits in the 100 kW to 2 MW range.

There is a high of 80 MW in New Mexico and a low of 20 kW in Wisconsin.

There is no capacity limit in Arizona, Colorado, New Jersey or Ohio.

Some states limit capacity to a percentage of the customer’s load (e.g. 125%).

Some states have limits determined by customer type.

In California, the individual system limit is 1 MW for all customers and 5 MW
for systems owned or operated by or on property under the control of a local
government or university. When California initially adopted net metering in
1995 a system cap of 10 kW was applied and expanded to 1 MW in 2001.

20 states and the District of Columbia have no aggregate capacity cap.

Other states impose a limit of a percentage of utility peak demand in the range
of 1-5%.

The state of Massachusetts has a cap of 6% of peak demand.

In California, the state net metering cap is a percentage of peak demand that
started at 0.5%, was raised to 2.5% in 2006 and in 2010 was further increased
to 5% of non-coincident peak demand or just over 5,000 MW, with a
technology specific cap for fuel cells only at 500 MW. In a September 2013
California Assembly Bill that passed with a unanimous vote, the regulator was
given a further mandate to expand the net metering programme, with certain
72
conditions.
Mulkern, Anne C. 16 September 2013. In sweeping rewrite, California overhauls rates, lifts net metering cap.
Governor’s Wind Energy Coalition website: http://www.governorswindenergycoalition.org/?p=6618 - accessed
18 September 2013.
72
44
Duration of contract

In California the contract duration is indefinite, up to the lifetime of the system.
Simplified
interconnection
procedures

Most US states have simplified interconnection procedures.

At the transmission level, the Federal Interconnection Standards for Small
Generators for systems up to 20 MW applies. Standard interconnection
procedures, a standard agreement and technical requirements are provided.
All generators must obtain liability insurance. The standards have provisions
for three levels of interconnection:
System or meter
specifications
(i)
The “10 kW inverter process” for certified, inverter-based systems
(ii)
The “fast track process” for certified systems up to 2 MW
(iii)
The “study process” for all other systems up to 20 MW
73

Interconnection at the distribution level is overseen by state public utilities
commissions. Many of these have adopted simplified procedures, sometimes
following the federal guidelines. California for example has simplified
74
procedures, based on which San Diego Gas & Electric has implemented a fast75
track process for systems up to 30 kW and Pacific Gas & Electric has a
Distribution Interconnection Handbook with simplified procedures and
76
automatic connection for systems meeting certain criteria.

Where automatic eligibility is not available, the utility will conduct a site
assessment and initial review prior to approving an application. In certain
cases a more detailed review may be required.

In California at the distribution level where a utility has secondary networks for
higher reliability with parallel lines and transformers (as opposed to radial
networks), normally in dense urban areas, the utility has the right to impose
special considerations and not accept any customer export. This is because of
the possible impact on network protection devices used to prevent power
back-feeding from one transformer to another and concern over network
protectors in service not being designed to support disconnections. The utility
may still agree to make the grid available to support self-generation but will
77
generally not accept any export.

These are covered in the applicable interconnection standards.

If a time-of-use rate is applied a meter capable of recording export and import
North Carolina State University. Interconnection Standards for Small Generators. Database for State
Incentives for Renewables and Efficiency,
http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=US06R&re=0&ee=0 - accessed 10 August
2013.
73
California Public Utilities Commission website. Net energy metering (NEM).
http://www.cpuc.ca.gov/PUC/energy/DistGen/netmetering.htm - accessed 19 August 2013.
74
San Diego Gas & Electric website. Apply for NEM – Less than 30 kW. http://www.sdge.com/cleanenergy/apply-nem/apply-nem-requirements - accessed 30 August 2013.
75
Pacific Gas & Electric Company website. Distribution Interconnection Handbook.
http://www.pge.com/b2b/newgenerator/distributedgeneration/interconnectionhandbook/index.shtml accessed 29 August 2013.
76
Pacific Gas & Electric Company website. Secondary Networks.
http://www.pge.com/b2b/newgenerator/secondarynetworks/index.shtml - accessed 29 August 2013.
77
45
separately is required. Otherwise a bi-directional meter can be used.
Time of use metering
Customer billing
changes and/or
compensation
Credit carry forward
Utility compensation
In California:

Public owned utilities may elect to offer co-energy metering, which is net
energy metering at a time-of-use rate.

Also, some investor-owned utilities offer an optional separate net metering
billing rate and it is up to the customer to decide to adopt such or remain with
their existing retail rate. The optional rate may or may not be a time-of-use
rate.

Otherwise the rate schedule is that normally applied to the customer category
for both import and export.

The state has previously considered but never adopted a separate “wholesale”
tariff for net metering that would be similar to a feed-in-tariff approach.

Compensation in California is described in the next section below for state
utilities.

For municipal utilities, provisions for net excess generation must be developed
through a separately public consultation process.
In California:

Surplus units are carried forward to the next billing cycle at the retail rate.

After 12 months, the net metering customer may either (a) opt to carry
forward the credits indefinitely or (b) receive payment for the credits at a rate
equal to the 12-month average spot market price between the hours of 07:00 –
17:00.

If the customer does not make a decision the credits are forfeited to the utility.

If the customer does not opt to receive payment, and it owns any Renewable
Energy Credits (RECs), it retains ownership of the RECs from that period. If the
customer opts to receive payment, the ownership of the RECs is transferred to
the utility and can be used towards meeting the utility’s Renewable Portfolio
Standards obligation.

For any net metering customers eligible for and applying net metering
“aggregation” or multi-site metering (see below), any surplus carried forward is
reset to zero at the end of a 12-month cycle.
These vary state-by-state. In California:

Utilities are barred from applying any new or additional demand charges,
standby charges, customer charges, minimum monthly charges,
interconnection or other fees that would increase a net metering customers
costs beyond those of other customers in the same rate category up to 1 MW.
Above 1 MW, utilities may apply certain charges.

However, regardless of the size of the facility utilities may apply a charge for
setting up the net energy meter and calculating the net metering bills.
46
Other features

In the case that a detailed net metering application assessment is required, the
customer must pay for the study.

If a net metering customer does not explicitly request to carry forward or
receive financial compensation of any excess credits in a 12-month period, the
credits are given to the utility.

If a customer receives payment for any surplus and has RECs for the period,
ownership of the RECs transfers to the utility.
In California:

“Virtual” net metering is allowed for multi-tenant properties, which enables
any excess credits to be distributed across all tenants’ bills.

Meter aggregation is allowed for local governments if all billing accounts
receive a time-of-use rate and the same government entity is involved. This
means that credits at one government premises can be used to offset bill
payments at another premises.

Meter aggregation for customers with multiple meters on parcels of land
contiguous to the renewable energy system is under consideration.

Utilities maintain a list of inverters and disconnect switches eligible for use by
net metering customers.
47
A7.2
Denmark
Denmark has set a target of 100% renewable energy in the energy and transport sectors by 2050. To
help reach this in the electricity sector, the country has a number of regulatory and incentive
mechanisms to promote large and small-scale distributed electricity generation from renewables
and co-generation. There is some overlap between some of the schemes of which as summary is as
follows, among others:

Purchase obligations (Feed-in-tariffs) for generators

Co-generation from district heating (both fossil fuel and biomass-based)

Collective and community ownership of renewable energy plants, including a
mandatory first offer of at least 20% shareholding to local residents on commercial
rates for wind projects

Renewable Energy System (RES) certificates – currently the programme appears to be in
hiatus

Financial schemes including green taxes and funding support for feasibility,
development, loans and research targeting small-scale, grid-connected systems

Net settlement (Feed-in-tariffs) for surplus electricity from producers primarily for own
consumption

Net metering for surplus electricity from producers primarily for own consumption
Denmark’s programmes for the export of surplus electricity generated for own consumption are
covered by different laws and regulations that are regularly updated and revised. This makes for
some complexity but encompasses various project types and provides flexibility to customers and
investors. Technical and procedural requirements are fairly straight-forward and simplified for
systems up to 6 kW. Denmark’s net metering, net settlement and related policies have a number of
interesting design features not generally seen in other countries.
A net metering mechanism was first piloted for solar PV in 1998. Even with Denmark’s relatively
high electricity prices it was not, however, until a 2010 amendment that significant net metering
uptake was seen: almost 400 MW of solar PV installed across 68,900 customers in just over two
years.
The policy rationale behind the Danish net metering and net settlement schemes are a combination
of the following:

Contribution to the 2050 renewable energy target and mitigating climate change

Contribution to 100% national self-sufficiency in energy production

Promotion of local ownership of and participation in renewable energy

Support for the development of new technologies and industries, including for export

Support to economic development
48
As of 2013 a number of incentives for net metering and distributed generation from solar PV and
other technologies are under review and may be subject to changes.
Country
Country size
42,430 sq km
Population
5,590,000
GDP per capita
USD 56,210 (2012)
sector
Agriculture: 1.3%
78
Industry: 22.1%
Main industries
Iron, steel, nonferrous metals, chemicals, food processing, machinery and
transportation equipment, textiles and clothing, electronics, construction,
furniture and other wood products, shipbuilding and refurbishment, windmills,
pharmaceuticals, medical equipment
National power system information (2011)
79
Installed capacity
13,586 MW (2011)
Electricity access
99.7%
~6,327 kWh/year
Generation
35,171 GWh/year (2011)
80
Grid mix
81
82
Technology
Coal
39.7%
Natural gas
16.5%
83
78
Danish Energy Agency. 2011. Energy Statistics data tables, p. 58
http://www.ens.dk/sites/ens.dk/files/info/facts-figures/energy-statistics-indicators-energyefficiency/annual-energy-statistics//Energy%20Statistics%202011.pdf
79
International Energy Agency. 2012. World Energy Outlook, 2011. Electrification rate, percentage of population:
http://www.iea.org/weo/electricity.asp - accessed March 28, 2012 (In the absence of data on electrification rate,
99.7% is assumed).
80
81
World Bank. http://data.worldbank.org/indicator/EG.USE.ELEC.KH.PC accessed 19 August 2013.
Danish Agency. 2011. Report on Energy Statistics, p. 11. http://www.ens.dk/sites/ens.dk/files/info/factsfigures/energy-statistics-indicators-energy-efficiency/annual-energystatistics//Energy%20Statistics%202011.pdf (Value converted from 126,617 TJ)
82
83
Danish Energy Agency. 2011. Report on Energy Statistics, pp. 11-12.
49
Peak load
Oil
1.3%
Renewable energy
40.2%
Non-renewable waste
2.3%
Peak load: 6,498 MW
Time of peak: 18:00
84
Peak month: November
85
T&D losses
7%
price per customer
category
Tariff
USD/kWh (2011)
Household
0.39 (KES 33.66)
Industrial
0.11 (KES 9.53)
Legal framework and key information 86 87 88 89 90 91 92 93
Nordic Energy Regulators. 2011. Nordic Market Report 3/2011, p. 20.
https://www.nordicenergyregulators.org/upload/Reports/nmr2011-final%20for%20publication.pdf - accessed
19 August 2013.
84
85
Danish Energy Agency. 2011. Report on Energy Statistics, p. 11 (Calculated 8639 TJ/126617 TJ).
Danish Energy Agency. Bekendtgørelse om nettoafregning for egenproducenter af elektricitet (Notice of net
metering for electricity auto-producers). 28 June 2010.
https://www.retsinformation.dk/Forms/R0710.aspx?id=132740 - accessed 18 August 2013, translated with
Google Translate.
86
Danish Energy Agency. Bekendtgørelse om nettoafregning for egenproducenter af elektricitet (Notice of net
metering for electricity auto-producers). 20 November 2012.
https://www.retsinformation.dk/Forms/R0710.aspx?id=144036 - accessed 18 August 2013, translated with
Google Translate.
87
EU Renewable Energy Policy Database and Support. Denmark net metering overview. http://www.reslegal.eu/search-by-country/denmark/single/s/res-e/t/promotion/aid/net-metering/lastp/96/ - accessed 19
August 2013.
88
89
Promotion of Renewable Energy Act no. 1392 of 27 December 2008 (unofficial English translation).
90
Danish Energy Regulatory Authority. 2012 annual report: results and challenges.
91
Energinet.dk. 2012 Consolidated Annual Report.
Danish Energy Agency. Bekendtgørelse om tilskud til at fremme udbredelsen af elproduktionsanlæg med
vedvarende energikilder (Notice of subsidies to promote the diffusion of power generation plants with
renewable energy sources). 26 June 2012. https://www.retsinformation.dk/Forms/R0710.aspx?id=142592 accessed 20 August 2013, translated by Google Translate.
92
Energinet.dk. 2011. Technical regulation 3.2.1 for electricity-generating facilities of 16 A per phase or lower.
http://energinet.dk/EN/El/Forskrifter/Technical-regulations/Sider/Regulations-for-grid-connection.aspx accessed 19 August 2013.
93
50

Promotion of Renewable Energy Act no. 1392 of 27 December 2008

Consolidation of the Act on Electricity Supply No 279 of 21 March 2012 and
earlier versions
Effective date

1998 (pilot programme)

2002 (first revision)

February 2004, Guidelines for net settlement of auto-producers.

15 December 2004, Executive Order no. 1364 on the granting of subsidies for
electricity generated at RE plants other than wind turbines.

15 December 2004, Executive Order no. 1366 on net settlement of autoproducers of electricity

14 February 2005, Guidelines for net settlement of auto-producers.

August 2007, Regulation D1: Settlement metering and settlement basis

November 2007, Regulation E: Settlement of environmentally-friendly
electricity generation.

11 June 2010, Law No 622: Notice of net metering for auto producers of
electricity.

28 June 2010, Executive Order no. 804: Notice of net metering for electricity
auto-producers.

15 December 2010, Decree No 1637: Notice of net metering for electricity
auto-producers.

26 June 2012, Notice of subsidies to promote the diffusion of power
generation plants with renewable energy sources.

20 November 2012, Executive Order no. 1068: Notice of net metering for
electricity auto-producers.

The incentive schemes presented herein are based on recent versions of
Denmark’s net metering and related regulations (2008 – 2012). Information
on incentives from earlier net metering regulations is not provided.

Renewable energy generators with own consumption apparently have the
choice to apply for either (a) payment for any surplus electricity with a fixed
price (Feed-in-Tariff) or (b) net metering using a bidirectional meter. For solar
PV systems up to 6 kW, however, no FIT is offered and net metering is the
only option.

For electricity generators with own consumption under a purchase obligation
(FIT), the following tariffs apply:
Incentive schemes
(i)
DKK 0.60 (USD 0.11 or KES 9.3) minus the market spot price per kWh
for wind, small hydro and biomass
(ii)
DKK 0.60 (USD 0.11 or KES 9.3) minus the market spot price per kWh
51
for the first 10 years and DKK 0.40 (USD 0.07 or KES 6.2) for the next
10 years in the case of biogas power plants only.

With a Nord Pool electricity market spot price in the range of EUR 0.0310.065/kWh (USD 0.041 – 0.087 or KES 3.59 – 7.53/kWh), this results in an
approximate FIT range of USD 0.02 – 0.07 or KES 1.8 – 5.3/kWh for surplus
electricity fed to the grid for wind, small hydro and biomass.

Furthermore, private generators under net settlement or net metering are
completely or partially exempt from the Public Service Obligation (PSO),
which is a levy per kWh charged on all electricity consumers depending on
certain circumstances. One component of the PSO is a surcharge used to
support renewable energy.

Under net metering and net settlement, installations exempt from the whole
PSO tariff are:

(i)
Solar energy installations up to 50 kW
(ii)
Wind energy plants up to 25 kW
(iii)
Other technologies up to 11 kW
Installations exempt from the renewable energy surcharge component of the
PSO are
(i)
Solar energy installations > 50 kW
(ii)
Wind energy plants > 25 kW
(iii)
Other technologies > 11 kW

In some specific circumstances, some types of “own consumption” are not
eligible to receive the PSO exemption.

In 2013 the Danish Transmission System Operator expects an average Public
Service Obligation of DKK 0.174/kWh (USD 0.031 or KES 2.7/kWh). With a
2012 average residential end-user tariff of USD 0.39/kWh (KES 33.7), this
would be an additional benefit to net metering customers of approximately
8% savings on their electricity bill. The savings may be more significant for
industrial customers even though larger systems are only eligible for a partial
PSO exemption due to the fact that the industrial tariff is much lower.

While not specific to net metering/net settlement, between 2008 and 2015
the Danish system operator (Energinet) is administering a support facility for
the promotion of grid-connected, small-scale renewable energy plants at with
total funds of DKK 25 million (USD 4.5 million, KES 385 million) per annum.
The funding is available in the form of grants or loans for feasibility studies,
development, installation, information dissemination and research and
targets emerging technologies such as building-embedded solar cells. The
source of the funding is the renewable energy component of the PSO.

Denmark has also been piloting Renewable Energy System (RES) certificates
as a further incentive but the scheme appears to still be in the early pilot
phase.
52
Achievements
Challenges

Tax deductions of 25% per year of the net value of the investment over the
first four years may also allowed but not linked to net metering per se.

Certain incentives are only provided for fixed terms and some of the early net
settlement and net metering customers are now operating on market terms.

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 by February 2013.

This compares with approximately 15 MW of solar PV capacity in the 19982010 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
94
decrease in module prices.

In addition, as of 2011 approximately 400 small-scale (<50 kW) wind turbines
have been installed, the majority at the residential level though most of these
are likely under the net settlement regime with a FIT-type purchase obligation
for surplus electricity rather than under net metering.

Albeit under net settlement (FIT for surplus power) and not net metering,
Denmark has also seen strong success in the establishment of district-level
combined heat and power plants for local electricity supply.

Micro-wind turbines have been targeted at rural household customers to help
realize reduced electricity costs as unlike urban consumers they do not have
access to cheaper energy from the combined heat and power plants.

Some net metering customers in Denmark have installations that produce for
the consumption of multiple end-users on site and/or use more than one
renewable energy source. There are often collectively or cooperatively
owned systems that are encouraged under the Act for the Promotion of
Renewable Energy (2008). This has also extended to local electricity
distribution/supply, with 60 of the 89 network companies being collectively
owned supplying more than 50% of Denmark’s customers.

The multitude of project types and circumstance under which renewable
electricity can be generated and exported by grid-connected customers has
necessitated a high level of detail in the various regulations.

Net settlement, net metering and related regulations in Denmark are subject
to frequent revision – at least every two years even not earlier. While this
means that the regulations are quick to respond to changing market
conditions it also places an administrative burden on customers, investors,
utilities, the ministry and the regulator.

The recent significant 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.
Photon.info. Denmark's PV capacity estimated to have reached 400 MW at the end of 2012. 2 February 2013.
http://www.photon.info/photon_news_detail_en.photon?id=73808 - accessed 19 August 2013.
94
53

No challenges in terms of system stability have been reported.
Overview of net metering programme design characteristics
Item
Technology types
permitted
Eligible customer
categories

All renewable energy technologies except geothermal, namely wind, solar PV,
small hydro, biomass, biogas, co-generation and wave power.

Cogeneration plants

Both customer categories (domestic and industrial) are eligible for net
metering or net settlement although for net metering only certain technology
types and system sizes may be eligible.

Private generators of renewable energy or electricity from co-generation
eligible for net settlement (FIT payments for surplus) are divided into five
categories with different requirements and incentives:
(i)
Group 1: Facilities operating on market terms [these are facilities are
that previously received incentive support that has since been
discontinued]
(ii)
Group 2: Facilities subject to a purchase obligation
(iii)
Group 3: Multi-fuel electricity generating facilities where only a part
of the generation is subject to purchase obligation
(iv)
Group 4: Installation-connected wind turbines irrespective of size and
installation-connected local plants with an installed capacity of less
than 50 kW
(v)
Group 5: Installation-connected facilities irrespective of size where
surplus generation is zero or insignificant.

It is up to the customer to assess the eligibility and financial attractiveness of
(a) no investment, (b) net metering or (c) net settlement with a purchase
obligation (FIT) depending on its specific circumstance. In the instance of solar
PV up to 6 kW, net metering is the only option.

General net settlement eligibility criteria:
(i)
Systems must be connected to a collective grid.
(ii)
Systems must be installed at the place of consumption.
(iii)
Systems must be fully owned by the consumer.
(iv)
For wind and solar PV only, the system must also be connected to
and used to meet some of the customer’s own consumption.
(v)
Except for systems of 11 kW and below, system including generation
data must be provided to the transmission system operator Master
54
Data Register.

Further eligibility criteria for net metering:
(i)
For all technology types, the system must also be connected to and
used to meet some of the customer’s consumption.
(ii)
In the 2010 version of the regulation, a further maximum limit of 6
kW or 100m2 per household appears to have been placed on net
metering systems at the family and apartment building level (the
translation of the Danish text is not entirely clear).

Furthermore, each new version of the regulation sets a time limit usually of six
months by which new systems must be installed to be eligible.

For net settlement (FIT for surplus) there is not express maximum system size
but one report mentions an installed capacity limit of 10 MWel.

For net metering, the 2010 version of the regulation may have imposed a limit
of 6 kW for a single unit or combination of units restricted to households and
apartments (the original Danish text is not clear when translated) and this may
only be for solar PV. In this case systems above 6 kW would be considered as
“production” units and eligible under net settlement.

In order to be eligible for the full (as opposed to partial) PSO exemption,
consumers must abide by a system cap of 50 kW for solar PV, 25 kW for wind
and 11 kW for other types of generators.

No aggregate system cap.

Denmark does not have individual contracts for net metering systems.
Instead, the “contract” duration is set for all customers from the date of entry
into force of the current net settlement or net metering regulation. Any
systems installed prior to that date continue to be eligible under the version
of the regulation that was in force at the time their net metering system was
connected. For example, in the case of the most recent revision of 20
November 2012, any customers connecting thereafter will benefit from net
metering up until 19 November 2032. This implies an effective term of 20
years if a customer connected on the date of entry into force, or a term of 17
years if the customer installed a net-metered system in November 2015.
Customers who connected before the entry into force are covered under the
previous (i.e. 28 June 2010) or early iterations of the net metering regulations.

With respect to the above, generally each new version of a regulation
nevertheless provides for a 20-, 15- or 10-year term as a minimum depending
on when the system was installed.

This may have the effect of easing the administrative burden on both the
customer and the utility, and assisting the utility with planning and responding
to net metering uptake as it occurs in cohorts, but it may also make it harder
for some customers to make an investment decision. However, once the
decision is made, there is certainty that a change in the regulation will not
affect the parameters that the customer used to assess the economic
attractiveness at the time of making the investment.
Maximum system size
55
Simplified
interconnection
procedures
System or meter
specifications
Customer billing
changes and/or
compensation

Net metering or settlement customers must follow the Danish grid code
guidelines. There are different technical specifications for grid connection and
operation for (a) power plants up to 11 kW, (b) between 11 kW and 1.5 MW,
(c) above 1.5 MW and (d) wind power plants above 11 kW.

Systems up to 11 kW follow simplified procedures.

Potential net metering customers must submit an application with at least one
month’s prior notice for determination. The utility decides if the customer is
eligible or not based on the net metering regulations.

Interconnection follows. Customers less than 50 kW are generally
automatically accepted.

The utility has a mandatory purchase obligation to offtake renewable power.
Renewable energy generators are not given priority for grid connection, but
once connected they have priority of dispatch/offtake.

The utility supplies the meters to be used. The net metering customer pays
for the installation and maintenance of the meters.

Either one bi-directional meter or two meters may be installed:
(i)
For solar PV and presumably other systems up to 6 kW under net
metering, a bi-directional meter is used and there is no need to
separately record generation as they are considered negative load.
(ii)
For systems above 6 kW under net settlement, a dual meter system is
installed and generation data must be recorded separately.

Where one customer site has multiple renewable energy generating systems
that are not each separately metered, the net metering calculation is based
proportionately on plant size and average generation according to published
guidelines. The customer pays a fee to the utility for such calculation.

Customers with more than 100 MWh of consumption per year must provide
more information to the grid operator.

For net settlement customers under a purchase obligation, time-of-use
metering is employed as the tariff depends on the Nord Pool hourly market
spot price.

For net metering customers, time-of-use is not recorded although this
possibility is there as more smart meters are installed.

For both net metered and net settlement customers, the PSO exemption is
noted on the bill.

For net settlement customers, billing may include payment for any surplus
electricity sold under a purchase obligation. This is apparently calculated and
paid on an annual basis.

Any adjustments and compensation In the case of collective systems with
multiple consumers but one single meter, the net metering import/export
balancing is calculated at the group level.

Under net metering the value of any electricity exported versus drawn from
56
the grid is equal regardless of time-of-use.
Other features?

For net settlement, bill balancing, including of any FIT or subsidy payments, is
computed on a monthly basis and either offset against the customer’s bill or
paid to the customer in each month that there is a surplus exported to the
grid.

For net metering, it is not clear what happens to any surplus credited although
without any indication otherwise presumably this can be carried forwarded
for the duration of the contract (i.e. 10, 15 or 20 years depending on the
regulation in force at the time of system installation).

The 2012 Energinet annual report states that: “Settlement on an annual basis
was practiced up to the end of 2012. In December 2012, the rules for solar PV
installations were amended to remove annual net settlement for new
systems”. No further details are provided on what this means, such as if any
annual credits can no longer be carried forward.

Costs for the meter installation and maintenance and grid connection are
borne by the customer, up to what the cost would be to connect to 10-20 kV.
All other costs, including grid extension and reinforcement, are borne by the
grid operator upfront and are recovered from rate-payers on a quarterly basis
as part of the Public Service Obligation (PSO).

If the grid operator agrees with the installation owner to make the grid
connection, it can recover these costs from the owner over a fixed period.

For any special calculations needs for complex net metering systems to assess
the net metering bill, the customer is required to pay.

For some types of generation facilities, they must pay a fee to the
transmission system operator for accessing the grid to sell its electricity.

The utility recovers part of any costs of or subsidies to net metering first from
its sales price on the regional electricity market (i.e. Nord Pool), which has a
spot price. When spot market prices are low, the subsidy amount is paid by
other customers as part of the PSO on a quarterly basis.

Information on the specific components of the PSO was not collected but
presumably it can be used to also cover any additional administrative costs
associated with net settlement and net metering. However, in Denmark
utilities also have annual mandatory efficiency targets to reduce their average
revenue requirements and where such gains are made regarding net metering
they may not need or be allowed to request to cost recovery in the PSO.

Where tenants of a dwelling or non-commercial building own an individual net
metering system and are metered individually, the net metering regulation
also applies. Presumably this means that a tenant can move to a new
premises, take their renewable energy system with them and continue to be
net-metered (and benefit from any surplus electricity exported) under the
version of regulation in force at the time the customer first installed their
system.

The Danish utility makes available a list of pre-approved companies and
equipment suppliers that can be engaged to ensure the grid connection
requirements are met.
57
A7.3
Tunisia
Since 2009, Tunisia has a law that gives industrial, agricultural and service industries as well as
residential customers that generate renewable energy for their own consumption the right to (a)
transfer any excess production to another site or (b) sell the excess to the national utility. It thus
allows for both power wheeling and net settlement or net metering. The law is limited to customers
in the low voltage categories (230 V to 30 kV) and individual system sizes are capped at the existing
contract size with the utility, with some exceptions. A specific programme for residential solar PV
net metering has simplified procedures and provides important financial incentives.
The main purpose of Tunisia’s net metering policy appears to be twofold: to increase the
penetration of renewable energy in a fossil fuel dominated grid and to help stimulate a local clean
energy industry. Net metering was also intended to increase the amount of grid-connected solar PV
capacity in the country based on prior successful experience with solar PV in off-grid rural
electrification and for water pumping and with solar hot water heating systems in urban areas. The
net metering policy will thus contribute towards one of Tunisia’s solar plan goals to establish 15 MW
of solar PV from 6,000 residential and 1,000 institutional/commercial systems. The short-term goal
for residential solar PV net metering was 1.5 MW from approximately 1,000 installations by 2011.
By the end of the pilot phase in February 2012, a total of 739 systems and 1.3 MWp were in installed
against 1,400 customer requests totaling 2.4 MWp. The uptake among other eligible categories of
net metering customers and technology types is unknown.
There are important incentive schemes for net metering in Tunisia, especially for solar PV. This is
due to the relatively low to moderate end-user electricity price that may not otherwise promote
investment.
Country
Size
155,360 sq km
Population
10,780,000
GDP per capita
USD 4,237 (2012)
sector
Agriculture: 8.9%
95
Industry: 29.6%
Services: 61.5% (2012 estimate)
Main industries
Petroleum, mining (particularly phosphate and iron ore), tourism, textiles,
footwear, agribusiness, beverages.
95
58
National power system information (2011) 96
Installed capacity
4,024 MW
Electricity access

99.6% electrification rate

3.27 million low voltage customers
97
~1,562 kWh/year
Generation
16,834 GWh/year (2012)
Grid mix
Type
Natural gas
39%
Combined cycle
31%
Thermal (fuel or gas oil)
27%
Hydro
2%
Wind
1%
Peak load
98

3,024 MW (13 July 2011 at 13:30).

Peak load: 13:00 – 14:00.

Strong demand occurs between 09:00 – 17:00, with a smaller, shorter
duration secondary peak around 20:00.
T&D losses
2,255 GWh or 14.1% (2011)
price per customer
category
Tariff
USD/kWh (2011)
99
Low Voltage
Economic bracket 1
(1 to 2 kVA and ≤ 50kWh/year)
0.046 (KES 3.92)
Economic bracket 2
(1 to 2 kVA and
> 50kWh/year)
96
97
Société Tunisienne de l'Electricité et du Gaz (STEG). Rapport annuel 2011.
Calculated based on GWh energy sales / population.
Benedetti, Luca et al. May 2013. Tunisia Energy Country Report: focus on electricity sector and renewable energy
policies, p. 17. http://qualenergia.it/sites/default/files/articolo-doc/%252fCOUNTRY_REP_TUNISIA.PDF
98
Benedetti, Luca et al. May 2013. Tunisia Energy Country Report: focus on electricity sector and renewable energy
policies, p. 21. http://qualenergia.it/sites/default/files/articolo-doc/%252fCOUNTRY_REP_TUNISIA.PDF
99
59
1 to 50 kWh/month
0.056 (KES 4.80)
≥ 51 kWh/month
0.081 (KES 6.94)
Ordinary bracket
(>2kVA)
1 to 300 kWh/month
0.081 (KES 6.94)
≥ 301 kWh/month
0.113 (KES 9.71)
Medium Voltage
Normal
0.076 (KES 6.53)
Time of use
Day
0.067 (KES 5.74)
Peak
0.102 (KES 8.77)
Evening
0.081 (KES 6.94)
Night
0.052 (KES 4.44)
Water pumping
Day
0.077 (6.58)
Peak
0.095 (KES 8.15)
Evening
Load shedding
Night
0.052 (KES 4.44)
Safety tariffs for self-producers in case
of necessity
Day
Peak
Evening
Night
0.078 (KES 6.68)
0.109 (KES 9.40)
0.091 (KES 7.83)
0.055 (KES 4.70)
60
Legal framework and key information 100 101 102 103

Loi n°2004-72 du 2 août 2004 relative à la maîtrise de l’énergie

Loi n°8-2009 du 9 février 2009 de la maîtrise de l’énergie

Décret n°362-2009 du 9 février 2009

Décret n°2009-2773 du 28 septembre 2009

While not a law, Tunisia’s project for the promotion of electricity selfgeneration from solar PV (project Prosol ELEC) is specific to residential
systems and targeted a total of 1.5 MW of solar PV installed on approximately
1,000 buildings by the end of 2011.
Effective date
2 August 2004
9 February 2009
Incentive schemes
Incentives for residential solar PV net metering are available. For all other net
metering systems no information was found on incentives.
Under Décret n°362-2009:

For buildings implementing solar PV primarily for own consumption a subsidy
of 30% of the investment cost is available with a maximum limit of 3,000
Dinars (USD 1,800 or KES 155,000) per kWp up to 15,000 Dinars (USD 9,000 or
KES 780,000) per system. The subsidy is provided by the National Fund for
104
Energy Conservation.
Under Tunisia’s project for the promotion of electricity self-generation from solar
PV (project Prosol ELEC) for residential customers:

An additional subsidy of 10% of the investment cost, supported by funds from
the Italian Ministry of Environment via the Mediterranean Renewable Energy
Centre

A five-year loan of up to 3,000 Dinars (USD 1,800 or KES 155,000) per kWp
from a local commercial bank, repayable on the electricity bill. The interest
Agence nationale de la maîtrise de l’énergie et Société tunisienne de l’électricité et du Gaz. Promotion de
l’autoproduction d’électricité par l’énergie solaire photovoltaïque. Présentation du projet. Décembre 2009.
http://www.steg.com.tn/fr/prosol_elec/presentation.html - accessed 14 August 2013.
100
Ministère de l’industrie et du commerce. Contrat d’achat par la STEG de l’excèdent de l’énergie électrique produite a
partir de l’énergie solaire photovoltaïque par le producteur résidentiel en basse tension souscrivant pour 1 et 2 kWc.
http://www.steg.com.tn/fr/prosol_elec/Demandes_Formulaires.html - accessed 14 August 2013.
101
Ministère de l’industrie et de la technologie. Contrat d’achat par la STEG de l’excèdent de l’énergie électrique
produite a partir d’énergies renouvelables et livrée sur le réseau basse tension.
http://www.steg.com.tn/fr/prosol_elec/Demandes_Formulaires.html - accessed 14 August 2013.
102
Ministère de l’industrie, de l’énergie et des petites et moyennes entreprises. Décret n°2009-2773 du 28 septembre
2009 fixant les conditions de transport de l’électricité produite a partir des énergies renouvelables et de la vente de ses
excédents a la société tunisienne de l’électricité et du Gaz.
103
Agence nationale pour la maîtrise de l’energie. L’Energie solaire photovoltaïque en Tunisie,
http://www.anme.nat.tn/anme1/wd1/photovoltaique/photo-voltaique/ - accessed 14 August 2013
104
61
rate is around 5%.

A bonus of the total of the interest rate charged on the loan equivalent to a
subsidy of 5% of the system investment cost, from the Italian Ministry of
Environment
The financial incentives, including the loan disbursement, are only made available
after the system is operational. An upfront cash outlay must still be made by the
property owner and/or the installation company.
Achievements
Challenges

701 residential net metered solar PV installations between 2009 and the end
105
of 2011 under Prosol ELEC.

By the end of the Prosol ELEC pilot phase in February 2012, a total of 739
systems and 1.3 MWp were in installed against 1,400 customer requests
totaling 2.4 MWp. This is against a target of 1.5 MW from approximately
1,000 residential (including apartments) systems by 2011, with an average
system size of 1-2 kWp and a likely maximum size of 5 kWp given the above
incentives.

In addition, the net metering support programme facilitated the emergence
of 30 new solar PV installation companies and the establishment of the first
unit of a PV module manufacturing facility with an annual capacity of 25
106
MWp.

No information is available on the electricity produced or exported.

The uptake among other categories of net metering customers and
technology types is unknown and was likely minimal as of 2011 since the
utility annual report that includes self-generators did not make note of any
renewable energy projects.

For residential solar PV net metering, the utility notes that it is generally
customers consuming an annual average of 5,000 kWh and above who will
realize economic viability from net metering.
Item
Technology types
permitted
105

All renewable energy technologies are permitted.

In addition, a simplified programme with financial incentives is available
specifically for residential customers deploying solar PV.
Société Tunisienne de l'Electricité et du Gaz (STEG). Rapport annuel 2011, p. 12.
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.
106
62
Eligible customer
categories
Maximum system size

All industrial, agricultural or service industries and residential premises that
generate renewable energy for their own consumption.

Limited to customers in the low or distribution voltage categories. For
residential solar PV this is defined as 230 or 400 V. For all other net metering
customers this is 10, 15 or 30 kV.

Under the project Prosol ELEC, residential customers are also eligible only if
the following circumstances apply:
(i)
the customer is the owner of the property
(ii)
the property has sufficient surface area
(iii)
annual electricity consumption is a minimum of 2,000 kWh

Only for those whose electricity bill payments are up to date.

Maximum installation size is equal to the size of the existing contract with the
utility.

In the case of non-residential customers, there is also a cap on the amount of
electricity permitted for export, being 30% of the customer’s self-generation,
except in the case of biomass power where this does not apply but the
installed capacity may not exceed 15 MWel.

For residential solar PV net metering customers the individual system size
targeted is between 1 and 2 kW. Larger systems are allowed; however, the
investment subsidy is limited to the first 5 kW.

There is no explicit aggregate cap.

The Tunisian solar plan targets 15 MW of grid-connected solar PV from 6,000
residential and 1,000 institution/commercial customers.

The project Prosol ELEC has an initial target of 1.5 MW from residential
systems at approximately 1,000 sites up to June 2011.

The contract starts from the date of acceptance of commissioning of the
project by the utility

The contract is for the period up to 31 December each year and is
automatically renewed except as follows:

(i)
The contract can be suspended in case of force majeure or temporary
breach by the customer
(ii)
The contract can be terminated by the utility in case of extended
breach of contract or if electricity supply by the utility is stopped
(iii)
The contract can be terminated by the customer if the renewable
energy system ceases to function
In the case of termination by either party, 30 days notice must be given for
residential solar PV and 60 days for larger systems.
63

Simplified procedures apply for residential solar PV customers.

For residential solar PV, system installers are obliged to assist customers with
the application and administrative procedures with the utility.

There is a one-page application form for residential customers. For others,
the procedure is similar to that of a power plant under a PPA.

The utility-customer contract is for residential solar PV is four pages and is
seven pages for other customer types/technologies. The contract has simple
annexes for residential solar PV and more detailed annexes for larger net
metering customers.

For large net metering customers, the annexes include an interconnection
agreement. All interconnection upgrades up to the point of supply are borne
by the customer/distributed generator.

In the case of larger net metering customers, detailed interconnection
arrangements similar to those found in a PPA are required.

The utility makes available approved guidelines on technical specifications and
safety measures.

Both single and triple-phase connections are accepted.

The system must be capable of being isolated from the grid.

Under the project Prosol ELEC for residential customers, the utility is
responsible for providing the inverters.

A new meter for electricity export is installed along side the existing meter for
consumption.

For customers other than residential deploying solar PV, the meter must be
class 2.

For customers other than residential solar PV, insurance must be obtained and
maintained.

Not explicitly. However, in the case of medium voltage connections, one of
the tariff categories set by the Ministry of Energy has time-of-use
differentiation that may be applicable to net metering customers.
Customer billing
changes/any
compensation

Customer billing by the utility is based on the balance of electricity supplied
and drawn. The rate is that of the low voltage customer category for both
export and supply, which in 2012 was approximately EUR 0.06/kWh (USD
107
0.079 or KES 6.83).

In the case of a negative electricity bill (surplus electricity exported) in a given
month, the amount is carried forward to the next month. This applies to all
net metering customers, large and small.

For residential solar PV only, in the case that a customer takes a loan,
Simplified
interconnection
procedures
System or meter
specifications
projets d’énergie renouvelable en Afrique du Nord. Rapport final pour l’Economic Commission of Africa, p. 28.
107
64
repayment of the principle with interest is added to the customer electricity
bill, either monthly or bi-monthly.

In the case that it is necessary to stop the offtake of exported electricity, the
utility can do so and must restart offtake as soon as practical. The customer is
not eligible to receive any compensation for deemed energy.

Yes. Any unused surplus from a net metering customer can be carried
forward each billing period (monthly) for an indefinite duration.

Not under net metering, but under the Prosol ELEC incentive scheme the
utility has the additional responsibility of (a) transmitting loan disbursement
requests to the participating bank and (b) recovering the loan repayments via
the customer’s bill and remitting these to the bank. It is not clear if the utility
is compensated for this additional administrative burden.

For prospective solar net metering customers, an application fee of 35 Dinars
(USD 21 or KES 1,800) is payable, but only when the application is accepted.

The utility is also allowed to charge a management fee of EUR 15 (USD 20 or
KES 1,700) per system to administer the incentive schemes noted above.

The utility is responsible for meter installation and operation at its own cost.
There is apparently no compensation to the utility for this. The utility must
also pay for any periodic calibration. However, if the customer requests for
testing of the accuracy of the meter it must pay for the test.

The installation company must pay the cost of the inverter to the utility in
case of damages before commissioning.

There is a list of companies pre-qualified to install the solar PV systems.

For solar PV users, the National Agency for Energy Conservation pre-approves
the equipment that may be deployed.

There is mutual liability - the utility or customer is responsible for any
damages to facilities or persons of the other party.

If the occupant of the premises changes, they must inform the utility. It is not
stated what happens if the owner changes.
Other features
65
A7.4
Mexico
Country
Size
1,943,945 sq km
Population
116,220,947
GDP per capita
USD 9,742 (2012)
sector
Agriculture: 4.1%
108
Industry: 34.2%
Services: 61.8%
Main industries
Food and beverages, tobacco, chemicals, iron and steel, petroleum, mining,
textiles, clothing, motor vehicles, consumer durables, tourism.
National power system information 109
Installed capacity
52 218 MW (2013)
Electricity access
98.11 %
1,990 kWh/year (2010)
Generation
257,530 GWh (2012)
Grid mix
Technology
Thermal
44.83%
Hydro
21.58%
Coal
4.98%
Geothermal
1.58%
Wind
0.17%
Nuclear
3.08%
Photovoltaic
0.01%
Thermal IPPs
22.80%
Wind IPPs
0.98%
108
109
http://www.cfe.gob.mx
66
Peak load
n/a
T&D losses
n/a
price per customer
category
Sector
USD/kWh (2012)
Domestic
0.89 (KES 76.20)
Commercial
1.99 (KES 170.38)
Services
1.50 (KES 128.42)
Agriculture
0.01 (KES 0.86)
Medium-sized industry
0.95 (KES 81.33)
Large industry
0.72 (KES 61.65)
Legal framework and key information
Modelo de Contrato de Interconexión para Fuente de Energía Solar en Pequeña
Escala (Model contract for the interconnection of small scale solar energy
sources) – 2007 [RES/176/2007]
– 2010 replaced by Modelo de Contrato de Interconexión para Fuente Colectiva
de Energía Renovable o Sistema Colectivo de Cogeneración Eficiente en Pequeña
Escala (Model contract for the interconnection of small scale solar energy
sources) states that the elecricity supplier will install the net meter at the
generator’s cost. [RES/054/2010]
Ley para el Aprovechamiento de las Energías Renovables y el Financiamiento de
la Transición Energética (Law for the Use of Renewable Energy and the Financing
of Energy Transition) – 2008
Programa Sectorial de la Energía 2007-2012
Effective date
7 June 2007
2010 - model contract was substituted [RES/054/2010]
Incentive schemes
Preferential transmission tariff for RE & efficient cogeneration
MX$ 0.14/kWh instead of MX$ 0.30-0.40/kWh
110
Fondo para la Transición Energética y el Aprovechamiento Sustentable de la
Energía
110
http://mim.promexico.gob.mx/work/sites/mim/resources/LocalContent/42/2/Energias_Renovables_ES.pdf
67
Energy bank

Grid acts as bank for energy supplied by generators

Energy is supplied back to users in later periods

Price = tariff at that interconnection point (according to contract)

At end of year, generator may sell the accumulated energy to CFE at
85% of CTCP or bank it for up to 12 months (from supply)
Accelerated depreciation

Up to 100% in first year

According to Ley del Impuesto sobre la Renta 2005, Art. 40 (law on
income tax)

Only applicable to firms (not residential users) as it is intended to
provide an incentive to invest in RE generation

Minimum length of operation is 5 years
Fideicomiso para el Ahorro de Energía Eléctrica (FIDE, Trust for the saving of
electric energy)
Achievements
n/a
Challenges
n/a

Financing of interconnected systems > 500 kW

Up to 100% financing, special interest rate

Only available to firms, not residential users

Repayment: > 5 years; quarterly payments
Item
Technology types
permitted
Any RE or cogeneration up to 500 kW
Eligible Customer
categories
Small scale
Residential
General use at low voltage (1 kV)
68
Medium scale
General use (1-69 kV) - for local use only
Maximum system size
Small scale
Residential >10 kWp
General use > 30 kWp
Medium scale
General use > 500 kW
n/a
Unlimited
Simplified
interconnection
procedures
1) Application
2) Issuing of application number
3) Comisión Federal de Energía (CFE) personnel will check that the unit meets
the technical requirements and standards
4) Signature of interconnection contract and payment (see below)
5) CFE installs the bi-directional meter
6) Interconnection contract starts.
System or meter
specifications

PV unit has to meet CFE specifications and standards - Normas Oficiales
Mexicanas (NOM) [specified in Anex E-RMT and E-RDT]

The CFE installs the required meters and bills the generator for the
difference with respect to the cost of the normal meter. Any additional
meters may be installed at generator’s own cost.
Yes, depends on existing tariff (normal or time-of-use) determined in existing
supply contract
Customer billing changes
and/or any compensation
Billing remains the same, according to existing tariff (normal or time-of-use) and
contract for low voltage.
Yes, banking mechanism if energy supplied exceeds consumption in that period
(month). The amount will be credited against future bills which are “negative”,
i.e. the energy consumed exceeds that supplied. Banked quantities may only be
credited against energy bill within the following 12 months.
n/a
Other features
n/a
69
A7.5
Sri Lanka
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 totaling 4.5 MW supplying 7,000
households and 160,000 solar home systems totaling 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”.
The policy was furthermore implemented as a specific alternative to requests for a solar Feed-inTariff from project developers and as a way to build local solar industry experience. Net metering
further contributes to the implementation of Sri Lanka’s 2006 National Energy Policy that includes
fuel diversification and security of supply in electricity among its strategic objectives and promotes
the “involvement of the country’s population in the investment, operation, regulation and delivery
of energy services”.111 It will also help achieve Sri Lanka’s target of 10% energy supply from “nonconventional” renewable sources by 2015 – large hydro already contributes 25-50% to Sri Lanka’s
generation.
The Sri Lankan situation is roughly comparable to that of Kenya with similar electricity prices,
installed capacity, generation mix, load profile, peak demand and others. Sri Lanka also has
significant experience with small-scale (<10 MW) embedded generation from distributed renewable
sources with 331 MW installed and 259 MW contracted under it’s Feed-in-Tariff since 1996
contributing 6.4% to the national generation mix in 2012. This experience helped familiarize the
country with distributed generation and inform the net metering policy. Since inception, Sri Lanka’s
net metering programme has resulted in 700 kW installed across approximately 300 customers, with
an average system size of 2 – 4.5 kW. The uptake is mostly solar PV in the high-end residential
customer category with monthly consumption of at least 160 kWh. Due to an absence of any
negative grid impacts, in July 2012 the net metering programme was expanded from the initial
individual system cap of 40 kW (42 kVA) to include systems up to 10 MW.
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.
Country
Size
62,710 sq km
Population
20,330,000
GDP per capita
USD 2,923 (2012)
sector
Agriculture: 11.1%
112
Industry: 31.5%
Services: 57.5% (2012)
Ministry of Power and Energy. 2008. National Energy Policy and Strategies of Sri Lanka.
http://www.ceb.lk/sub/db/op_nationalenergy.html - accessed 18 August 2013.
111
112
70
Main industries
Processing of rubber, tea, coconuts, tobacco and other agricultural commodities;
telecommunications, insurance, banking; tourism, shipping; clothing, textiles;
cement, petroleum refining, information technology services, construction
National power system information (2012) 113
Installed capacity
3,312 MW
Electricity access

93 - 94% (Estimated, 2012 Ceylon Electricity Board).

77%

4.98 million customers.
114
(2012 World Bank).
~515 kWh/year
Generation
11,801 GWh/year
Grid mix
Technology
% of total capacity
Large hydro
23%
Small hydro
5%
Thermal fuel
59%
Coal
12%
Wind, solar, biomass
1.4%
Peak load
115
Sri Lanka’s load profile is very similar to that of Kenya.
Peak demand: 2,164 MW (9 May 2012)
Peak time: 18:00 – 22:00
T&D losses
10.67%
Average retail
electricity price per
customer category
Tariff
USD/kWh
Domestic
Block 1 first 30 units
Unit rate
Fuel adjustment Fee
0.02 (KES 1.95)
116
25% = 0.006 (KES 0.49)
All power sector figures unless otherwise noted are taken from Ceylon Electricity Board. Statistical Digest
2012. http://www.ceb.lk/sub/publications/statistical.aspx - accessed 14 August 2013.
113
114
World Energy Outlook 2012.
Note: 2012 was a year of poor hydrology in Sri Lanka. In 2010 and 2011 hydro contribute to 40-52% of the
generation mix. See for example: Sri Lanka Energy Balance 2010 Report, p. 20.
http://www.energy.gov.lk/pdf/Energy_Balance_2010.pdf
115
Fuel adjustments charge is applied only on monthly energy charge. It is not applied on monthly fixed charge
http://www.ceb.lk/sub/residence/tariffplan.html - accessed 20 August 2013.
116
71
Fixed charge
0.23 (KES 19.53) per month
Block 2 31-60 units
Unit rate
0.04 (KES 3.06)
Fuel adjustment Fee
35% = 0.012 (KES 1.07)
Fixed charge
Block 3 61-90 units
Unit rate
0.06 (KES 4.88)
Fuel adjustment Fee
40% = 0.023 (KES 1.95)
Fixed charge
Block 4 91-180 units
Unit rate
0.16 (KES 13.67)
Fuel adjustment Fee
40% = 0.064 (KES 5.47)
Fixed charge
Unit rate
0.18 (KES 15.56)
Fuel adjustment Fee
40% = 0.073 (KES 6.25)
Fixed charge
Block 6 above 600 units
Unit rate
0.27 (KES 3.44)
Fuel adjustment Fee
40% = 0.109 (KES 9.37)
Fixed charge
Religious Purpose
Unit rate
0.014 (KES 1.24)
Fuel adjustment Fee
-
Fixed charge
Block 2 31-90 units
Unit rate
0.021 (KES 1.82)
Fuel adjustment Fee
-
Fixed charge
Unit rate
Fuel adjustment Fee
Fixed charge
0.051 (KES 4.39)
1.363 (KES 117.18) per month
Unit rate
0.057 (KES 4.88)
72
Fuel adjustment Fee
-
Fixed charge
Block 5 above 180 units
Levelized cost of
household solar PV
with batteries
Unit rate
0.071 (KES 6.12)
Fuel adjustment Fee
-
Fixed charge
USD 0.215/kWh (2012)
117
Legal framework and key information 118 119 120 121

Sri Lanka Electricity Act, no. 20 of 2009 and its Electricity Supply Code

Distribution Code of Sri Lanka
Effective date

January 2009

July 2012 (Distribution Code)
Incentive schemes

Sri Lanka does not have any specific incentive schemes for net metering.

The National Energy Policy (2008) establishes an Energy Fund for small-scale
renewable generators but it is not clear if and how this currently offers any
incentives for net metering.

From 1997 – 2011 a World Bank and Global Environment Facility (GEF) support
project entitled Renewably Energy for Rural Economic Development (RERED)
provided USD 83 million in grants, credit lines and technical assistance but only
for (a) rural, off-grid communities and (b) small-scale grid-connected projects
122
under the Feed-in-Tariff. It is conceivable that a small number of customers
now under net metering may have benefited from this support where formerly
off-grid households have become grid connected.
Wickramasinghe, Harsha. Sri Lanka Sustainable Energy Authority. Net metering scheme of Sri Lanka: a
presentation. Presentation to KPLC and ERC, Nairobi, Kenya, 13 June 2013.
118 Wickramasinghe, Harsha. Sri Lanka Sustainable Energy Authority. Net metering scheme of Sri Lanka: a
presentation. Presentation to KPLC and ERC, Nairobi, Kenya, 13 June 2013.
117
Public Utilities Commission of Sri Lanka. Distribution Code of Sri Lanka. July 2012.
http://www.pucsl.gov.lk/english/wp-content/uploads/2012/11/Distribution-Code-July-2012.pdf
119
Lanka Electricity Company (LECO). 2010. Net Metering Terms and Conditions.
http://leco.lk/?page_id=415 - accessed 14 August 2013.
120
Siyambalapitiya, Tilak. Net Metering of Electricity has Arrived! The Island Online (Sri Lanka). 14 January
2009. http://www.island.lk/2009/01/14/features1.html - accessed 14 August 2013.
121
Renewable Energy for Rural Economic Development Project.
http://www.energyservices.lk/statistics/details_shs1.htm - accessed 18 August 2013.
122
73
Achievements
Challenges

From policy inception in 2009, 700 kW of net metering have been installed to
date in aggregate across approximately 300 customers, presumably all in the
residential category.

The average individual system size is 2 – 4.5 kW.

No adverse grid impacts noticed, hence the net metering programme is being
expanded.

By comparison, as of March 2013 Sri Lanka had achieved 331 MW of
operational small-scale (< 10 MW) renewable IPPs under its Feed-in-Tariff,
contributing 730 GWh or 6.3% of Sri Lanka’s electricity generation in 2012. A
123
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.

A related achievement is that due to potential national and regional demand
from net metering and other programmes, the Lanka Electricity Company, one
of the two Sri Lankan utilities, has established a domestic high-tech energy
meter manufacturing facility with an annual production capacity of 500,000
124
units.

High-end domestic customers – considered as those with 160 kWh or more
consumption per month – in Sri Lanka are the category most likely to adopt
net metering, partially because below that level electricity tariffs are
subsidized. These customers make up only 4.2% of electricity sales but
account for 35% of utility revenue. A significant uptake in net metering would
have an affect on the load profile during the daylight hours as the hypothetical
technology of choice would be solar PV. Significant uptake has not been
experienced to date and if it occurs is expected to displace other renewable
generation only if it is in the margin.

Significant uptake would also affect utility revenue and the source of funds for
the cross subsidy in the national uniform tariff. In an extreme case of all highincome customers adopting solar PV net metering at a total cost of USD 860
million (KES 74 billion), utility revenue losses of USD 168 million/year (KES 14
billion) might occur against generation cost savings of USD 85 million (KES 7.3
billion).

Recent tariff increases are showing signs of increasing customer interest in net
metering.

It has been further noted that net metering customers using solar PV would
benefit from a tariff differential by exporting surplus electricity during the day
when the marginal cost is approximately USD 0.10/kWh (KES 8.58) and
importing units in the evening during peak load when the cost is USD
0.13/kWh (KES 11.16).

However, since the purpose of the net metering policy is to support national
renewable energy development, possible compensation measures to address
utility revenue concerns have not been implemented. If they were to be, in
addition to the USD 0.03/kWh (KES 2.57) disparity noted above, it is estimated
Ceylon Electricity Board website. Present Status of Non-Conventional Renewable Energy Sector (as at
31/03/2013). http://www.ceb.lk/sub/db/op_presentstatus.html - accessed 14 August 2013.
123
Lanka Electricity Company website. Net Metering. 7 May 2012. http://leco.lk/?p=317 - accessed 14 August
2013.
124
74
that banking charges of USD 0.045 – 0.06/kWh (KES 3.86 – 5.15) could be
necessary to compensate the utility and cross subsidy loss depending on the
customer profile.
Item
Technology types
permitted
Eligible customer
categories
Maximum system size

Hydro, wind, solar, biomass and industrial, agricultural or municipal waste.

For residential customers, solar PV is the most likely technology.

Initially in 2009 only one of the two Sri Lankan utilities, the Lanka Electricity
Company (LECO), adopted net metering. This was followed in June 2010 with
adoption by the other utility, the Ceylon Electricity Board (CEB), facilitating net
metering for all grid-connected customers in the country.

Initially eligibility was limited to customer categories in the low voltage range
(230 V, 400 V) with a maximum contract size of 40 kW/42 kVA, both single and
three-phase.

This has recently (July 2012) been increased to 10 MW and 11 or 33 kV.

From 2009-mid 2012, 40 kW or 42 kVA or the existing contract size was set as
the individual system cap.

In July 2012 due to no adverse affects the limit was increased to 10 MW or the
maximum contract size, in line with the upper project limit under Sri Lanka’s
small power producer Feed-in-Tariff programme.

Customers are furthermore expected to limit their system size so that at most
monthly generation equals average demand.

Not explicitly indicated for net metering.

The National Energy Policy has an initial target/limit of 10% of electricity from
small-scale renewables, which presumably includes net-metered production.

A review of technical limits and financial constraints for small-scale RE will be
carried out from time to time.

20 years.

The utility may temporarily disconnect the system and/or suspend the contract
in the case of (a) emergencies, (b) maintenance or modifications or (b) noncompliance by the net metering customer. There is no compensation for any
deemed energy.

The contract may be terminated in case of breach or non-compliance by either
party as well as non-payment of electricity bills by the customer, with 30 days
written notice.
75
Simplified
interconnection
procedures
System or meter
specifications
Customer billing
changes/any
compensation

There are simplified procedures for 230 and 400/415 V net metering customers
with demand up to 42 kVA. This includes a two-page application form and an
11-page contract.

New protection equipment must be installed by the customer.

For residential PV net metering customers, it is usually the solar equipment
supplier who facilitates the process.

An accredited chartered electrical engineer must conduct the generator and
interconnection testing and commissioning at the customer’s cost. A utility
representative must witness the successful operation of the system.

Larger customers in the 1-2 MVA and higher range up to 10 MW must connect
(or continue to connect) at 11 or 33 kV levels and may on a case-by-case basis
have more stringent procedures equivalent to a small-scale embedded
125
generator under a PPA.

Net metering customers must buy and install a bi-directional meter.

Solar PV system inverters must comply with strict grid code requirements for
disconnection and reconnection after power failure and harmonics for grid
stability, power quality and safety reasons. Furthermore, utility personnel
must be able to have immediate and 24 hour access to a manual disconnection
switch.

All equipment must adhere to relevant industry standards (e.g. IEC, IEEE) or be
subject to a laboratory test approved by the utility.

No, a unit exported is considered equivalent to a unit imported regardless of
the time of use.

However, a time of use tariff is under consideration.

A special electricity bill format is used for net metering customers and is
computed manually until an automated system is introduced.

The electricity bill for customers connected at voltages above 400 V are more
detailed than those for smaller customers.

Customer monthly billing is the difference between electricity drawn from and
exported to the grid in the billing period.

In the case of any surplus electricity exported, this is credited and carried
forward. No payment is made by the utility.

Yes. The credit can be carried forward for future billing periods up to a
maximum of 10 years.

If the owner of the net-metered system moves to a new location, s/he is able
to take the “banked” electricity credits with them. Nevertheless, in some cases
a change of ownership or system relocation may be grounds for contract
Ceylon Electricity Board website. Grid connection procedures.
http://www.ceb.lk/sub/business/electricityconn.html - accessed 18 August 2013.
125
76
termination.
Other features

One-time application fee of LKR 2,000 (USD 15 or KES 1,200).

Utility site visit and assessment fee of USD 125 (KES 10,700).

Customer pays for the system costs, any re-wiring of the premises, a new
reverse-flow meter, lockable circuit breaker and any other protection
equipment

The utility is not compensated for providing the electricity banking service or
for any additional administrative burden, as net metering is seen as a
contribution by the utility towards the national development of renewable
energy.

The Sri Lanka Sustainable Energy Authority makes available a simple Excel tool
for prospective net metering customers to assess the economic viability of
solar PV systems.

Power wheeling by net metering customers is not permitted.

The utility is not liable for any damages to customer property or persons except
in the case of negligence. Otherwise there is mutual liability.
77
A7.6
Morocco
Country 126
Size
446,550 sq km
Population
32,649,130 (2013)
GDP per capita
USD 2,925 (2012)
sector
Agriculture: 15.1%
127
Industry: 31.7%
Services: 53.2%
Main industries
Phosphate rock mining and processing, food processing, leather goods, textiles,
construction, energy, tourism.
Installed capacity
6,677 MW (2012)
Electricity access
98.9 %
28,752 kWh/year
Generation
20,090 GWh/year (2009)
Grid mix
128
Peak load
126
129
Technology
Gas
14.1%
Oil
19.2%
Hydro
7.0%
Wind
2.4%
STEP
0.5%
Imports
16.1%
Coal
40.7%
Peak load: 4,890 MW
https://www.cia.gov/library/publications/the-world-factbook/geos/mo.html
127
128
http://www.mem.gov.ma/ChiffresCles/Energie/CHIFFRES%20CLES%20SECTEUR%20ENERGIE%202011.pdf
78
Time of peak: Oct-Mar 17-22; Apr-Sep 18-23
T&D losses
n/a
price per customer
category
Tariff
USD/kWh (current)
0 to 100 kWh
0.11 (KES 9.42)
101 to 200 kWh
0.11 (KES 9.42)
201 to 500 kWh
1.25 (KES 107.02)
> 500 kWh
1.71 (KES 146.41)
130
131

National Renewable Energy and Energy Efficiency Plan (2008)

Moroccan Solar Plan (2009)

Law 16-08, voted in 2008, raised the ceiling for self-generation by industrial
sites from 10MW to 50MW.

Law 13-09 (Renewable Energy Law) allows for private generation from RE
sources and electricity exports. It grants the right to private generators to be
connected to the low, medium and high voltage networks. The new law does
not put a limit on the installed capacity per project or per type of energy, and
provides a legal framework for clean energy export.

There is no legislation referring to net metering specifically
Effective date
2009
-
Incentive schemes

Power Purchase Agreement, augmented by competitive bidding: The tariff is
negotiable between the operator and the distributor or is already fixed. The
agreement is generally set up for 20 - 25 years and ownership of the
renewable energy electricity plant is generally transferred entirely to ONE
afterward.

Feed-in Tariffs (project)

Tradable Clean Development Mechanism

Subsidies: participation of 20% in the operating expenses; 5% in investments
129
http://www.mem.gov.ma/ChiffresCles/Energie/CHIFFRES%20CLES%20SECTEUR%20ENERGIE%202011.pdf
130
http://www.one.org.ma/fr/pages/interne.asp?esp=1&id1=3&id2=113&t2=1
131
http://www.nortonrosefulbright.com/knowledge/publications/66419/renewable-energy-in-morocco
79
and 20% in the employees training cost: contribution to the cost of the
training when hired and in-service training. Grants: 10% on capital
expenditure with a ceiling of 200,000DH
Achievements
132
Challenges

Access to finance: ONE, as well as the Société d'Investissements Energétiques
(SIE) and the Energetic Development Fund (FDE) (both financed by sovereign
funds) can take an equity contribution to the project. It can also provide soft
loan or loan guarantees

Tax-free zones: According to the area, the project can be exonerated of taxes
and VAT.

EnergiPro programme (2006): applies to industrial firms generating their own
power from RE sources up to 50 MW. The state-owned utility ONE would
commit to buying any excess power from the firms at an incentive tariff
(originally equivalent to 20% more of the peak tariff) for 25 years.

Mini-generation: 10% of funds from national rural electrification programme
were allocated to home solar PV systems. By end of programme (2010): only
60,000 out of 250,000 homes (planned) had systems installed with a total
capacity of 4MW.

It’s success was measured by rural electrification which increased from 15%
in 1996 to 98%.
Morocco has a track record of implementing renewable energy schemes.
However historically, inadequacy of regulatory framework, a lack of finance, and
a piecemeal approach to renewables have all hindered the sector’s development.
Item
Technology types
permitted
All renewables.
Eligible customer
categories

Small (no requirement)

Medium (require declaration to ONE)

Large (require authorisation by ONE)

Small < 20 kW

Medium 20 kW – 2 MW

Large > 2 MW
Maximum system size
132
n/a
OECD
80
25 years
Simplified
interconnection
procedures
Equipment grant: the ONE's equipment grant covers 66% of the equipment costs
enabling electrical service at affordable rates: the connection fees of rural solar
customers reduced by 40% which bring them closer to the urban electricity rates.
System or meter
specifications
n/a
n/a
Two compensation mechanisms are available:

Provision of a service: ONE commissioned a private company close to the
beneficiaries to install the PV systems and to provide after-sales service and
debt collection.

Fee-for-service partnership: The private operator is in charge of
implementing the solar program, managing the technical and financial
aspects of the program, performing maintenance on the installed systems,
replacing equipment and collecting users’ fees in twenty-four Moroccan
provinces. Customers pay an initial connection fee and a monthly service fee.

The net metering customer can sell any surplus electricity to the utility at a
negotiable price, which should be around 60% of the medium voltage utility
retail sale price, less a fixed fee of approximately EUR 0.07/kWh (USD 0.092
133
or KES 7.97) for use of the grid.
n/a
n/a
Other features
Because there is no particular legislation in relation to net metering, not many
specifications regarding the “programme” are available.
projets d’énergie renouvelable en Afrique du Nord. Rapport final pour l’Economic Commission of Africa, p. 28.
133
81
A7.7
Uruguay
Country
Size
176,215 sq km
Population
3,324,460
GDP per capita
USD 14,449 (2012)
sector
Agriculture: 8.2%
134
Industry: 21.6%
Services: 70.3%
Main industries
Food processing, electrical machinery, transportation equipment, petroleum
products, textiles, chemicals, beverages.
Installed capacity
2,516 MW (2012)
Electricity access
98.9 %
2,763 kWh/year (2010)
Generation
9,500 GWh/year (2011)
Grid mix
135
Technology
Oil
Hydro
Imported power
Biomass
Wind
Peak load
8%
76%
4%
11%
1%
Peak load: 1,744 MW
134
135
http://www.miem.gub.uy:8080/gxpfiles/miem/content/video/source0000000062/VID0000050000002121.pdf
82
Time of peak: 18:00 – 22:00
Peak month: July
T&D losses
n/a
price per customer
category
Tariff
136
USD/kWh (2012)
Residential Basic
0.26 (KES 22.26)
Residential Simple
0.28 (KES 23.97)
Residential Dual Rate Schedule
0.25 (KES 21.40)
General Simple
0.27 (KES 23.12)
Medium Users Triple Rate Schedule
(MC1= 0,23-0,40 kV)
0.23 (KES 19.69)
(MC2= 6,4-15-22 kV)
0.18 (KES 15.41)
(MC3= 31,5 kV)
0.17 (KES 14.55)
Large Users Triple Rate Schedule
(GC3= 31,5 kV)
0.15 (KES 12.84)
Large Users Triple Rate Schedule
(GC5= 110-150 kV)
0.12 (KES 10.27)
Legal framework and key information 137
Decreto 173/010 (2010) - Microgeneración
Resolución 1895/010
Resolución 1896/010
Effective date
1 June 2010
Resolución 163/010 (2010) – Reglamento medición de la energía intercambiada
(establishes the rules for the measurement of exchanged energy)
http://www.dne.gub.uy/web/guest/-/precios-medios-de-energia-electrica-con-y-sin-impuestos-paracuentas-tipo-cier136
137
http://www.sitiosolar.com/netmetering%20en%20Uruguay.htm
83
Incentive schemes
Ley Nº 16.906 “Promoción de Inversiones” (promotion of investments)



Achievements
Under Decreto Nº 02/007, firms investing in solar energy generation
equipment are eligible for an income tax exception during 5 years.
Under Decreto 354/009, investments in the national production of solar
equipment as well as the transformation of solar energy are (partially)
exempted of paying income tax for 12 years (6 years with 90% exemption, 3
years with 60% and 3 years with 40%).
Under Decreto 455/07, investors may be exempted of paying local taxes in
relation to the inputs of production, tariffs for the import of inputs as long as
they do not compete with the national industry, up to 100% return of VAT
for any materials and services related to the construction and production,
complete exemption of paying property tax for up to 8 years in the capital
and 10 years in the rest of the country.
n/a
84
Item
Technology types
permitted
Eligible customer
categories
Solar, wind, biomass and mini-hydro
Low Voltage (residential, ≤ 1000 Volts)
 Low: ≤ 200 kWh/month
 Medium: ≤ 600 kWh/month
 High: > 600 kWh/month
Low voltage commercial and industrial
Maximum system size
Low Voltage (micro)

11 kW
Low Voltage (mini)
 150 kW
In both cases, limited to the customer contract size
Large Scale
 206 MW (solar PV)
10 years for both low voltage and large scale customers
Simplified
interconnection
procedures
Simplified procedures are available for “micro-generators” in the Low Voltage
category up to 150 kW.
1) Signing of Convenio de Conexión (connection agreement)
2) Presentation of a document assuming responsability for microgeneration
(Documento de Asunción de Responsabilidad (DAR))
3) Presentation of sworn declaration that the technical requirements are met
4) Signing contract of purchase and sale of electricity
UTE (state-owned utility) will charge a connection fee for the installation of the
bi-directional meter. All costs for such must be covered by the generators.
However, it is the utility’s responsibility to install the meter.
Regulations for interconnection are available here.
System or meter
specifications


No.


Yes, in the case of individual net metering customers.
No in the case of corporate entities. Instead, the utility is bound to buy any
energy that is not consumed at the tariff set in the contract (i.e. net settlement).
A bi-direction meter is required.
Meter specifications are provided in Resolución 163/010 (Art. 9)
No, customer will be billed according to tariff set out in contract.
However, for categories 1 and 2, the utility will pay a premium over the
contractual tariff for power supplied to the grid as an incentive for early
interconnection and generation.
85
Other features
n/a
Any investment will have to consist of at least 20% of national inputs (excl.
acquisition or rent of buildings). If the national component of the investment is <
20%, the price of power generated will be reduced by 10%.
86
A7.8
South Africa
In September 2011, South Africa adopted net metering as part of the Standard Conditions for
Embedded Generation within Municipal Boundaries.138 In South Africa, most of the larger
municipalities buy power from the national generator Eskom, private generators or municipalowned generators and have responsibility for distribution to end users. The 2011 standard allows
for systems up to 100 kW in size connected to these municipal networks. A second embedded
generation for systems larger than 100 kW is currently under development.
Following publication of the standard, in February 2012 the City of Cape Town initiated a netmetering pilot project to allow three domestic energy producers to feed electricity back into the
grid. The pilots were used to assess the technical impacts on the grid among other aspects.139
Shortly after, net metering tariffs were established and an application process launched but no
information on uptake is available.
Other municipalities are undertaking a similar process.140 The Nelson Mandela Bay Municipality, for
example, has prepared an interim “guideline document” for net metering or small scale embedded
electricity generation.141 Earlier in 2008, Nelson Mandela Bay had begun piloting a small-scale
energy project involving a residential and an industrial customer to determine the feasibility of
private installations supplying renewable energy to the grid. The Municipality does not remunerate
pilot users for this energy but is investigating the best compensation mechanism, either via net
metering or power purchase agreements.142
The main purpose of South Africa’s net metering policy appears to be a measure to reduce electricity
demand and reduce the country’s carbon footprint.143 Since the load shedding of 2008, there has
been increased interest in embedded generation from customers, which has been boosted by the
availability and decreasing cost of renewable energy options in the market.144 Furthermore, at the
2009 Copenhagen climate change conference South Africa committed to reduce its carbon emissions
by 34% in 2020 and 42% by 2025, conditional on finance, technology and capacity-building support
National Energy Regulatory of South Africa (NERSA). September 2011. Standard Conditions for Embedded
Generation within Municipal Boundaries. http://www.ameu.co.za/library/industry-documents/nersa/ - accessed
25 August 2013.
138
Engineering News website. 15 February 2012. Cape Town initiates net metering pilot project.
http://www.engineeringnews.co.za/article/cape-town-initiates-net-metering-pilot-project-2012-02-15 - accessed
25 August 2013.
139
Knox et al. 2012. KSEF Guide to Embedded Power Generation Application Procedures in KwaZulu – Natal, KZN
Sustainable Energy Forum.
140
Southern African Alternative Energy Association website. 20 February 2012. Net metering approval – South
Africa. http://www.saaea.org/1/post/2013/07/net-metering-approval-south-africa.html - accessed 25 August
2013. Nelson Mandela Bay Municipality. Small Scale Embedded Generation Application Form and Interim
Requirements for Small-Scale Embedded Generation.
http://www.nelsonmandelabay.gov.za/Documents.aspx?objID=74&cmd
141
Urban Earth website. 14 August 2012. Nelson Mandela Bay Municipality pilots embedded energy project.
http://urbanearth.co.za/articles/nelson-mandela-bay-municipality-pilots-embedded-energy-project - accessed
25 August 2013.
142
143
NERSA. September 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, p. 3.
144
Ibid.
87
from the international community.145 While South Africa’s power sector is dominated by coal-fired
generation, domestic targets on the use of renewable energy have been set146 and incentivizing the
use of renewable energy through measures such as net metering will contribute towards this goal.
Country
Size
1,213,090.00 sq km
Population
51,190,000
GDP per capita
USD 7,508 (2012)
sector
Agriculture: 2.6%
147
148
Industry: 29.3%
Main industries
149
Mining (world's largest producer of platinum, gold, chromium), automobile
assembly, metalworking, machinery, textiles, iron and steel, chemicals, fertilizer,
150
foodstuffs, commercial ship repair.
Installed capacity
45,216 MW (2006 & 2013)
Electricity access
76%
151
152
Department of Environmental Affairs website. South African Government’s Position on Climate Change.
http://www.climateaction.org.za/cop17-cmp7/sa-government-position-on-climate-change - accessed 16 August
2013.
145
146
NERSA. September 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, p. 4.
World Bank. World Development Indicators website: http://data.worldbank.org/country/ - accessed 16
August 2013.
147
148
Central Intelligence Agency. The World Fact Book website: https://www.cia.gov/library/publications/theworld-factbook/fields/2012.html - accessed 16 August 2013.
149
Central Intelligence Agency. The World Fact Book website: https://www.cia.gov/library/publications/theworld-factbook/fields/2090.html - accessed 16 August 2013.
150
Value is obtained by adding 2013 Eskom effective capacity (41,919 MW) and 2006 municipality and private
generator capacity (1850 and 1447 MW) respectively). Eskom Holdings SOC Ltd. 2013. Shift performance, grow
sustainably: Supplementary and Divisional Report for the Year Ended 31 March 2013, p. 38 and National Energy
Regulator of South Africa (NERSA). 2006 Electricity Supply Statistics for South Africa, p. 46.
http://www.nersa.org.za/Admin/Document/Editor/file/News%20and%20Publications/Publications/Current
%20Issues/Electricity%20Supply%20Statistics/Electricity%20supply%20statistics%202006.pdf.
151
152
International Energy Agency. World Energy Outlook 2012.
88
153
~4,803 kWh/year
Generation
239,803 GWh/year (2006 & 2013)
Grid mix
Technology
% of total capacity (2006 & 2013)
Gas fired
6%
Hydro
5%
Nuclear
4%
Coal
85%
Bagasse/coal
0.23%
Peak load
Peak load: 35,525 MW
154
155
156
Peak time: 17:00 – 21:00
Peak season: May – August (winter)
157
T&D losses
7%
price per customer
category
Tariff
158
USD/kWh (2013)
Homepower Bulk < 500V
0.11 (KES 9.13)
Homepower 1 Block 1
0.08 (KES 6.96)
Homepower 1 Block 2
0.13 (KES 10.98)
Homepower 2 Block 1
0.08 (KES 6.96)
World Bank. World Development Indicators website: http://wdi.worldbank.org/table/5.11 - accessed on 6
September 2013.
153
Value is obtained by adding 2013 Eskom generation (232,749 GWh) and 2006 municipality and private
generation (1,150 and 5,904 GWh) respectively. Eskom Holdings SOC Ltd. 2013. Shift performance, grow
sustainably: Supplementary and Divisional Report for the Year Ended 31 March 2013, p. 160 and NERSA, 2006
Electricity Supply Statistics for South Africa, p. 46
http://www.nersa.org.za/Admin/Document/Editor/file/News%20and%20Publications/Publications/Current
%20Issues/Electricity%20Supply%20Statistics/Electricity%20supply%20statistics%202006.pdf
154
155
Values obtained by taking into account Eskom 2013 data and 2006 municipalities and private generator data.
Eskom Holdings SOC Ltd. 2013. Shift performance, grow sustainably: Supplementary and Divisional Report for the
Year Ended 31 March 2013, p. 160
156
Calculated as the difference between total electricity sold by Eskom (216,561 GWh) and electricity sent out by
Eskom stations (232,749 GWh). Eskom Holdings SOC Ltd. 2013. Shift performance, grow sustainably: Supplementary
and Divisional Report for the Year Ended 31 March 2013, p. 164. According to NERSA 2006 data, estimated energy
loss is 11% (7.1% + 3.9%). NERSA, 2006 Electricity Supply Statistics for South Africa, pp. 52, 57.
157
Eskom Holdings SOC Ltd. 2013. Eskom Tariffs and Charges Booklet 2013/2014, p. 27 http://eskom.ensightcdn.com/content/ESKOM%20TC%20BOOKLET%202013-14%20FOR%20PRINT.pdf (values converted to
USD/MWh from c/KWh and R/KWh). Eskom tariff only included in this report (no local authority tariffs
available).
158
89
Homepower 2 Block 2
0.12 (KES 10.71)
Homepower 3 Block 1
0.08 (KES 6.96)
Homepower 3 Block 2
0.12 (KES 10.71)
Homepower 4 Block 1
0.08 (KES 6.96)
Homepower 4 Block 2
0.13 (KES 11.19)
Homelight 60 A
Block 10-600kWh)
0.08 (KES 6.58)
Block 2 (>600 kWh)
0.13 (KES 11.19)
Homelight 20 A
Block 1 (0-350 kWh)
0.07 (KES 6.21)
Block 2 (>350 kWh)
0.08 (KES 6.66)
Legal framework and key information 159

The Standard Conditions for Embedded Generation within Municipal
Boundaries, which is an official decision document of the National Energy
Regulator of South Africa (NERSA) under the Energy Regulator Act (Act No 40
of 2004), serves as the enabling legislation.

According to the standard, municipalities must also ensure compliance with
160
standard NRS 097-2-1:2010 Grid Interconnection of Embedded Generation.
Effective date
22 September 2011
-
Incentive schemes

No information was found on incentives for net metering.

General incentives for renewable energy include:
(i) The Renewable Energy Independent Power Producer Procurement
(REIPPP) Programme, which in 2011 replaced the nascent 2009 FIT
scheme. While small-scale (< 1 MW) installations are not eligible under
161
REIPPP, a small-scale procurement programme is under consideration.
(ii) Capital subsidies, grants or rebates, such as the Solar Water Heating
159
NERSA. September 2011. Standard Conditions for Embedded Generation within Municipal Boundaries.
NERSA. September 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, p.3 and
South African Bureau of Standards (SABS), NRS 097-2-1:2010: Grid Interconnection of Embedded Generators.
http://www.solarwholesale.co.za/NRS%20097-2-1.pdf.
160
Deutsche Gesellschaft furInternationale Zusammenarbeit (GIZ) GmbH. 2012. Legal Framework for Renewable
Energy: Policy Analysis for Developing and Emerging Economies, p.104.
161
90
Programme, which provides financial incentives for consumers to switch
162
to solar water heating. In the case that a solar PV system is used for
water heating it may be possible to size the array to generate surplus
electricity for own consumption and grid export and hence benefit from
the subsidy to participate under net metering.
(iii) In Cape Town, the municipality has a Green Electricity Certificate (GEC)
programme for green energy bought from the 5.2 MW Darling Wind
163
Farm. Net metering customers may be able to negotiate an
arrangement to participate as a supplier.
(iv) In Cape Town, residential net metering customers are offered a reduced
tariff for electricity consumed. This incentive is, however, partially
negated by a fixed daily service fee and an energy charge for each kWh
exported that must be paid to the utility.
Achievements
Challenges

No information is available on the total or average installed capacity or the
electricity produced or exported under net metering in South Africa as there
are very few participating municipalities and customers.

At least three municipalities are implementing (Cape Town, Nelson Mandela
164
Bay) or considering (eThekwini Municipality) net metering.

In Cape Town, three residential and small commercial pilot net metering
projects are operational, one being a rooftop 3.8 kWp solar PV system
165
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
166
test how storage may or may not play a role in net-metered systems.
In Cape Town, the following challenges have been identified:

The municipal utility has imposed a daily service surcharge for domestic net
metering customers (ZAR 10.6 or USD 1.03 / KES 88.79, excluding VAT) and an
energy generation charge for both domestic and non-residential – normally
small commercial (ZAR 0.4604/kWh or USD 0.045 / KES 3.86/kWh, excluding
VAT). The generation charge is 30-37% of the consumption tariff in the case
of domestic and 26-41% of the small commercial consumption tariff.
However, domestic net metering customers pay a reduced consumption tariff
Eskom Holdings SOC Ltd. 2011. CoP 17 Fact Sheet: Solar Water Heating Rebate Programme.
http://www.eskom.co.za/content/The%20Solar%20Water%20Heating%20(SWH)%20Programme.pdf
162
City of Cape Town website. About Green Electricity.
http://www.capetown.gov.za/en/electricity/GreenElectricity/Pages/default.aspx - accessed on 31 August
2013.
163
Municipal Institute of Learning. September 2012. Embedded Power Generation for Local Municipalities.
eThekwini Municipality, South Africa: http://www.mile.org.za/QuickLinks/News/Pages/news_20120904.aspx
- accessed 29 September 2012.
164
Engineering News website. 15 February 2012. Cape Town initiates net metering pilot project.
http://www.engineeringnews.co.za/article/cape-town-initiates-net-metering-pilot-project-2012-02-15 - accessed
25 August 2013.
165
SMA Sunny Portal website. Lovemore H., Port Elizabeth Plant Overview.
http://www.sunnyportal.com/Templates/PublicPageOverview.aspx?plant=c25b0fdc-500a-46f2-a9b43a509d6fe5c8&splang=en-US - accessed 30 August 2013.
166
91
(49-71% of the regular tariff) and the commercial net metering customers
avoid the ZAR 20.67 (USD 2.01 or KES 173) daily service charge applied to
other users in the same tariff category. The surcharges were implemented to
167
ensure the utility meets its fixed costs.

Overall, while net metering still offers benefits for customers, the above
charges have been criticized as being (a) “incredibly punitive”, (b) not taking
into account variations in customer system size and (c) generally hindering
168
net metering uptake. The utility has apparently recognized some of these
concerns as the 2013/2014 charges are lower than those initially established
169
in 2012/2013.

In the inception phase (July 2011) as net metering technical specifications had
170
not been finalized, all applications were placed on hold. Only customers
with self-generation systems larger than 100 kW who wanted to operate in
171
parallel to the grid were accepted. Since the September 2011 approval of
the embedded generation standard by NERSA this issue has presumably been
addressed.

Due to high levels of electricity theft, the city is moving to prepaid meters,
which may require a special design or dual meter reading.
In Nelson Mandela Bay, the following lessons have been taken from the pilot
172
projects:

Appropriate equipment is required in order to ensure that the quality of
electricity supplied meets the requirements. In particular connections using
low quality inverters can lead to problems.

New bi-direction meters will need to be installed.

Municipalities need to prepare for a loss of revenue that they may experience
from households investing in renewable energy.
City of Cape Town website. Electricity Tariffs.
http://www.capetown.gov.za/en/electricity/Pages/ElectricityTariffs.aspx - accessed 16 August 2013.
167
Keen, G.A. 2012. Compensating Grid-Tied Small Renewable Energy in Cape Town: What do the Renewable Energy
Citizens Want? Some Notes for Decision Makers, p. 3.
http://www.kznenergy.org.za/download/projects/WhatDoTheRECitizensWant090512.pdf
168
169 Urban Earth website. Cape Town introduces net metering tariff for domestic and small commercial users. 1
October 2012. http://urbanearth.co.za/articles/cape-town-introduces-net-metering-tariff-domestic-and-smallcommercial-users - accessed 30 August 2013.
Urban Earth website. Cape Town introduces net metering tariff for domestic and small commercial users. 1
October 2012. http://urbanearth.co.za/articles/cape-town-introduces-net-metering-tariff-domestic-and-smallcommercial-users - accessed 30 August 2013.
170
City of Cape Town. 2011. Electrical Requirements for Embedded Generation. http://www.sapvia.co.za/wpcontent/uploads/2011/10/ElectricalRrequirements-for-Embedded-Generation-29-07-11.pdf - accessed 31
August 2013.
171
25 August 2013.
172
92
Item
Technology types
permitted
Eligible customer
categories
Maximum system size
177

No technology types are indicated under the NERSA standard. Thus all
renewable and non-renewable energy sources are eligible.

The embedded generator shall however be type approved, unless otherwise
173
agreed upon with the utility.

There is indirect emphasis on solar PV. The NRS 097-2 guidelines aim to be
technology neutral and focus on the interface between the embedded
generator and the utility. However, it is expected that they will mainly apply to
174
solar PV interfaced through static power converter technology.

Customers connected to a municipal distribution network.

In Cape Town, net metering is available for approved connections provided
176
that their purchases exceed their generation in two categories:
175
(i)
All residential
(ii)
Non-residential (normally small commercial) where monthly
consumption exceeds 1,000 kWh/month. This minimum limit is set
due to separate regulations regarding meter type used.

100 kW (standards for larger systems are currently under development),
further limited to the rating of the premises supply point.

In the case of long feeder spurs the generator capacity might require utility
approval and might require a three-phase connection.

Eskom South Africa applies a distribution network limit for embedded solar PV
generation customers. The limits are specific to solar PV, presumably to allow
room for other distributed generation technologies. It is not clear how these
limits might interact with the NERSA-approved 100 kW limit as Eskom does
not operate municipal networks:
(i)
At the MW customer or MV level in aggregate, <= 15% of MV feeder peak
load.
(ii)
For LV customers or at the LV level in aggregate, <= 75% of transformer
rating, plus:
South Africa Bureau of Standards. NRS 097-2-1: 2010 Grid Interconnection of Embedded Generation, p.7 at 4.1.1.5.
http://www.solarwholesale.co.za/NRS%20097-2-1.pdf.
173
174
Ibid “Introduction“
175
NERSA. 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, p.4 at clause 15.
176
South Africa Bureau of Standards. NRS 097-2-1: 2010 Grid Interconnection of Embedded Generation, p. 8 at 4.1.1.64.1.18.
177
93
179
(a)
For LV customers with dedicated feeders, maximum of 75% of
maximum contract demand in kVA, balancing for multi-phase
generators >4.6 kW and a maximum generator size of 13.8 kW for
single phase customers
(b)
For LV customers with shared feeders, maximum of 25% of demand,
balancing for multi-phase generators >4.6 kW, total shared
generation not exceeding 25% and allowed individual system limit of
178
20 kW.

There is no explicit aggregate net metering cap.

The Integrated Resource Plan 2010-2030 for Electricity forecasts the
implementation of additional 16,383 MW coal-fired power plant capacity and
17,800 MW for renewables, of which 8,400 MW is expected to come from
wind, 8,400 MW from solar PV and 1,000 MW from CSP, by 2030 – a
significant increase in the renewable energy target since the 2003 White
180
Paper. The national policy goal as of 2011 is for achieving 10% penetration
for wind and PV technologies as a share of total installed capacity in 2020, and
181
20% in 2030.

Presumably renewable energy under net metering will be considered towards
these targets.

No information is available on the duration of a net metering contract.
Simplified
interconnection
procedures

No simplified procedures are enumerated.

However the NERSA standard clarifies that applicants for embedded smallscale generation are excluded (unlike other generation applicants) from the
requirement to be licensed or registered. Any control and record keeping is to
be done at the municipal level.

To qualify for a net meter tariff customers need to complete an embedded
generation interconnection application form (6-9 pages) from their
municipality and meet several technical requirements regarding metering and
safety. All prospective net metering customers must have the utility conduct
a preliminary assessment.

NRS 097-2-1:2010 Grid Interconnection of Embedded Generation describes the
technical issues and the responsibilities related to interconnecting an
embedded generator to a utility network, including:
(i) Automatic disconnection switch with a clear, descriptive label.
(j) Earthing in accordance with SANS 10142-1.
MacColl, Barry. 29 August 2012. Eskom. Embedded PV Generation – Considerations (presentation at Solar Power
Africa).
178
Fontana, Lido; Prestedge, Michaela and Jenna Wise. 16 July 2013. History of Renewable Energy in South
Africa. Bowman Gilfillan website. http://www.bowman.co.za/News-Blog/Blog/History-of-Renewable-Energyin-South-Africa - accessed 31 August 2013.
179
180
Department of Energy. May 2011. Electricity Regulations on the Integrated Resource Plan 2010-2030, p. 6.
181
Department of Energy. May 2011. Electricity Regulations on the Integrated Resource Plan 2010-2030.
94
(k) Short-circuit protection in accordance with IEC 60364-7-712.
(l) Voltage, current and frequency compatibility with IEC 61727.
System or meter
specifications

Municipalities such as Nelson Mandela Bay
supplementary interconnection guidelines.

Bi-direction meters are sufficient.

However, municipalities are encouraged and in the case of premises with
consumption >1,000 kWh/month obliged to install smart meters that can:
182
and Cape Town have set out
(i)
Handle separate measurement of bi-directional power flows.
(ii)
Handle the different time-of-use metering periods.
(iii)
Measure and record peak demand in different periods.
183

All meters utilized by the utility shall be the property of the utility even when
the meters are located on the premises of the customer. Meters that are
embedded in the customer’s network shall be accessible to the utility on
184
request.

Three metering configurations are acceptable in the case of premises where
embedded generators are operated. One applies to net metering where price
symmetry is given between consumption and generation and two
185
configurations apply to feed-in tariff (FIT) metering.

Utilities are responsible for the installation of the metering equipment.

Embedded generators larger than 10 kW shall be of the 3-phase type (the 10
kW refers to the maximum export potential of the generation device).

A customer with a multiphase connection shall split the embedded generator
over all phases if the system is larger than 6 kW.

Balancing phases in a multiphase embedded generator is deemed desirable.

The NERSA standard does not explicitly differentiate between a unit exported
and one imported under net metering.

However, provision is made for municipalities to implement time-of-use
metering for certain customers. In these cases the municipality must report to
186
Green Business Guide website. 8 July 2013. Reverse metering in the Nelson Mandela Bay Metro.
http://www.greenbusinessguide.co.za/reverse-metering-in-the-nelson-mandela-bay-metro/ - accessed 30
August 2013.
182
183
NERSA. 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, p.4 & 5 at clause 17.
South Africa Bureau of Standards. NRS 097-2-1: 2010 Grid Interconnection of Embedded Generation, p.13 at clause
4.3.1.1.
184
185
Ibid clause 4.3.1.2.
NERSA. September 2007. Distribution Network Code, v5.1. Clause 8.2 (3).
http://www.nersa.org.za/Admin/Document/Editor/file/Electricity/TechnicalStandards/Distribution%20Grid
%20Code/RSA%20Distribution%20Network%20Code%20Ver%205_1.pdf
186
95
NERSA on an annual basis the total energy each technology has generated
onto their system in each “Time of Use Tariff” metered time period. Further,
municipalities are to install smart metering which can handle the different
187
Time of Use (TOU) metering periods .
Customer billing
changes and/or
compensation

As per the NERSA standard the final consumer bill will be the net quantity of
energy that the customer consumes from the municipal network (total import
– total export).
In Nelson Mandela Bay:
188

The billing period is proposed to be monthly.

For the pilot project, surplus exported electricity is compensated with an
equivalent amount of grid energy supplied free of charge. Normal residential
189
charges continue for energy imported.

The municipality is investigating the best option for remuneration, either
190
through a net metering system or via purchase power agreements.
However, under net metering in no case would any financial payments be
made for surplus export, which would be forfeited in exchange for a reduction
in other charges.
In Cape Town, as noted above:

The municipal utility has imposed:
(i)
A daily service surcharge for domestic net metering customers of ZAR
10.6 (USD 1.03 / KES 88.79), excluding VAT.
(ii)
An energy generation charge for both domestic and non-residential –
normally small commercial of ZAR 0.4604/kWh (USD 0.045 / KES
3.86/kWh), excluding VAT.

The generation charge is 30-37% of the consumption tariff in the case of
domestic and 26-41% of the small commercial consumption tariff.

However, at the same time:
(i)
187
Domestic net metering customers pay a reduced consumption tariff
(49-71% of the regular tariff) and
NERSA. 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, clauses 2c & 17 b.
August 2013.
188
Knox A. et al (2012) KSEF Guide to Embedded Power Generation Application Procedures in KwaZulu- Natal, Kwa
Zulu Natal Sustainable Energy Forum, p.24.
189
25 August 2013.
190
96
(ii)
Small commercial customers avoid the ZAR 20.67 (USD 2.01 or KES
173) daily service charge applied to other users in the same tariff
191
category.

The NERSA standard defines net metering as the ability of the embedded
small-scale generator to be rewarded for energy that they may produce that
192
goes out onto the municipal grid. The nature of reward is not defined and
municipalities could therefore choose to allow customers to receive the credit
as cash, or to roll over the credits /carry them forward to the next period.

As mentioned above, in Nelson Mandela Bay the compensation mechanism is
still under consideration.
In Cape Town:
193

Net metering is only available for customers whose purchases exceed their
generation, meaning no net payment will ever be required.

The service charge (for residential customers) and energy charges (per kWh
for residential and non-residential) described above were implemented to
194
ensure the utility meets its fixed costs.

In addition, the costs for the utility performing the site assessment are paid by
the customer

An additional meter-reading fee may be applicable.
In Nelson Mandela Bay:
196
Other features
195

The customer will be required to pay 50% of the cost of the metering
equipment.

An administration fee in the range of ZAR 200 – 400 (USD 20 – 40 or KES 1,675
– 3,350) is under consideration.

Any surplus electricity exported may be forfeited after a period in exchange
for a reduction in other charges that may be applied by the utility.
The National Energy Regulator of South Africa (NERSA) requires that
municipalities:
191
192
NERSA. 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, p.4 at 15.
193
194
August 2013.
195
NERSA. 2011. Standard Conditions for Embedded Generation within Municipal Boundaries, pp. 5 & 6 at clauses 1821.
196
97

Maintain a database of their embedded installations, including those under
net metering. The database must record as a minimum:
(i)
Technology of the generator
(ii)
Capacity installed
(iii)
Location (both on network and GPS)
(iv)
Whether there is storage associated with it
(v)
The standard agreement with these customers, and
(vi)
The applicable tariffs as approved by NERSA

Submit an annual report which details the number of installations and total
capacity for each technology as well as the total energy generated onto their
systems by each technology.

Provide a copy of the standard agreement and applicable tariffs.

Report any complaints that they have received from customers in the vicinity
of the embedded generator about their quality of supply.

Ensure the safety of operating personnel. As a minimum this means putting
visible notices on the circuits connected to the generator in addition marking
the locations on all operating diagrams.
98
A7.9
Jamaica
According to Jamaica’s National Energy Policy, one of the key strategies and actions for the country
to achieve its goal of a well defined and established governance, institutional, legal and regulatory
framework for the energy sector by 2030 is the “introduction of appropriate mechanisms for net
metering and wheeling procedures and standards to encourage the development of renewable
energy and cogeneration opportunities.”197
Following publication of the national policy, Jamaica’s Office of Utilities Regulation (OUR) released in
September 2011 the Jamaica Public Service Company Limited Standard Offer Contract for the
Purchase of As-Available Intermittent Energy from Renewable Energy Facilities up to 100 kW Revised
Determination Notice.198 The standard offer permits Jamaica Public Service Company Limited’s
(JPS) customers who generate electricity for their own use from renewable sources to sell their
excess energy to the national grid under a net billing arrangement.
Net billing was chosen as it facilitates the application of the fundamental regulatory principle of the
fair allocation of cost. Net billing recognizes that there is a difference in the price of the kWh
exchanged between the utility company and the customer and facilitates billing based on a set off of
amounts payable by the customer to JPS for kWh consumed by the customer from the grid and sums
payable by JPS in respect of KWh supplied by the customer to grid. This is in comparison to net
metering which would allow the customer supplying kWh to the grid to receive a benefit equivalent
to the retail tariff payable to JPS. This would compensate for costs that the customer has not
incurred (as the rate payable to JPS includes a calculation of JPS’s costs to operate and maintain the
entire energy infrastructure in Jamaica) and thus receiving a rate far in excess of the costs of
supplying its energy to the grid. The increased benefit to the customer supplying energy to the grid
would eventually have to be recouped from the other customers through the utility tariffs and/or a
subsidy, a situation the Jamaican government has felt is untenable.199
The main purpose of Jamaica’s net billing arrangement appears to be to increase renewable energy
intake to at least 20% of total demand by 2030.200 The net billing programme is intended to support
greater use of renewable sources of energy by encouraging electricity production by small
intermittent producers. Furthermore, the programme is expected to reduce transmission and
distribution losses.201
197
Ministry of Energy & Mining (2009) Jamaica’s National Energy Policy 2009-2030, Jamaica, p. 38
Available at http://www.our.org.jm/ourweb/sectors/electricity/documents?type=59 - accessed 23 August
2013
198
Jamaica Public Service Company Limited Standard Offer Contract for the Purchase of As Available
Intermittent Energy from Renewable Facilities up to 100kW, p. 2. Document available at
http://www.myjpsco.com/wp-content/uploads/StandardOfferContract_DeterminationNotice.pdf
199
Information available at http://www.our.org.jm/ourweb/sectors/electricity/documents?type=59 - accessed
28 August 2013, p. xii
200
Republic of Jamaica, Ministry of Science, Technology, Energy and Mining, Distributed Generation : A Power
Station in Every Home. http://www.mstem.gov.jm/?q=node/63 - accessed 23 August 2013
201
99
Country
Country size
10,830 sq km
Population
2,710,000
GDP per Capita
USD 5,472 (2012)
sector
Agriculture: 6.4%
202
Industry: 29.1%
Main industries
Tourism, bauxite/alumina, agro-processing, light manufactures, rum, cement,
metal, paper, chemical products, telecommunications
203
Total installed capacity
830 MW (2010)
Electricity access
92%
~2401 kWh/year
Generation
4,135 GWh/year (2012)
Grid mix
Technology
Wind
1%
Hydropower
2%
Slow speed diesel
11%
Medium speed diesel
21%
Oil fired steam
30%
Combined cycle
14%
Combustion Turbine
21%
204
205
206
207
World Bank. 2013. World Development Indicators website. GDP per capita (current USD).
202
Castalia 2012. Options to bring down the cost of electricity in Jamaica, p. 61 http://www.castaliaadvisors.com/files/Options_to_Bring_Down_Electricity_Costs_in_Jamaica_Castalia.pdf
203
204
World Energy Outlook 2012
Report by Jamaica Productivity center, p. 4 (404+1997 –residential and non-residential )
http://www.jpc.com.jm/docs/Generation%20and%20Distribution%20of%20Electricity%20in%20Jamaica.pdf
205
206
JPS Annual 2012 Report, p.39
Castalia 2012. Options to bring down the cost of electricity in Jamaica (values are based on effective capacity 2011
data including IPPs), p. 10
207
100
Peak load
Peak load: 620 MW
208
Time of peak: 19:30 – 21:30
209
210
T&D losses
24.2%
price per customer
category
Tariff
USD/kWh
Residential up to
0.35 (KES 30.08)
211
100 kWh/month
Residential up to
0.39 (KES 33.52)
300 kWh/month
Commercial (R20 rate) up to
0.39 (KES 33.52)
1,000 kWh/month
Large commercial and industrial
customers (R40 rate) up to 35,000
kWh/month
0.33 (KES 28.36)
Maximum demand of 100 kVA
Industrial customers (R50 rate) up
to
0.32 (KES 27.50)
500,000 kWh/month
Maximum demand of 1,500 kVA

The Jamaica Public Service Company (JPS) Limited Standard Offer Contract
for the Purchase of As Available Intermittent Energy from Renewable
Facilities up to 100 kW. (The “SOC”). Effective as of 30 September 2011 and
revised on 1 May 2012.

The SOC is established under the following laws:
(a) All Island Electric Licence (2001). Effective as of 12 April 2001 and revised
on 19 August 2011.
(b) Regulatory Policy for the Addition of New Generating Capacity to the
208
Castalia 2012. Options to bring down the cost of electricity in Jamaica, p. 61
209
Castalia 2012. Options to bring down the cost of electricity in Jamaica, p. 8 (based on 2009 data)
210
JPS Annual 2012 Report, p.39
The tariffs include fuel rates and non-fuel rates and exclude taxes. Castalia 2012. Options to bring down the cost
of electricity in Jamaica, p. 2
211
101
Public Electricity Supply System. Effective as of 1 July 2006.
Effective date
30 September 2011
1 May 2012
Incentive schemes
While not an incentive specific to net metering or distributed generation,
renewable power plants in Jamaica can generally sell electricity to the utility at a
maximum price of 15% above the short-term variable avoided cost of generation.
The pricing mechanism for the supply of energy to the national grid under net
212
billing arrangement incorporates this renewable premium.
Achievements

Net metering is currently in a pilot phase. At the start of the pilot in May
2012, the Minister of Energy signed 11 licenses for net billing participants.
213
This marked the birth of distributed generation in Jamaica.

No further information is available on the current number, category and
technology type of net metering customers.
Challenges
Challenges identified at the pilot stage include:
214

The slow finalization of proper connection standards.

An insurance coverage requirement has been difficult for both generators
and insurance companies to meet.

What is reported by some as an overly complex process for a net billing
connection, which can take months. As of August 2013, none of the licenced
pilot projects were operational.

Critics have argued that the gap between the rate for buying and selling
power to the grid is too large.
To solve the challenges and smooth the implementation, a subcommittee of the
Jamaica Energy Council was recently formed to cut red tape and ensure that
there are no obstacles to connection.
Overview of net metering programme design characteristics in Jamaica
Item
Technology types
permitted

All renewable energy technologies with a focus wind, hydro, solar and
215
biomass.
212Jamaica
Public Service Company Limited Standard Offer Contract for the Purchase of As Available
Intermittent Energy from Renewable Facilities up to 100kW, p. 2.
http://www.our.org.jm/ourweb/sectors/electricity/documents?type=59 - accessed on 23 August 2013.
Republic of Jamaica, Ministry of Science, Technology, Energy and Mining, Distributed Generation : A Power
Station in Every Home. http://www.mstem.gov.jm/?q=node/63 - accessed 23 August 2013
213
214
Ibid
Application for Licence to Supply as Available Intermittent Energy from Renewable Energy Facilities Up to
100 Kw to the Public Electricity System and Application for Interconnection Arrangement with JPS.
215
102
Eligible customer
categories

It is expected that in the 2-year pilot programme wind and solar PV will be the
216
most popular technology options.

Residential or commercial customers who generate their own electricity using
217
a facility that:
(a) Has a capacity of less than or equal to 100 kW in the case of commercial
or less than or equal to 10 kW in the case of residential customers,
(b) Uses renewable technologies as its primary source of power, and
(c) Complies with all relevant technical specifications and standards as are
set out in the standard contract.
Maximum system size

Must be an existing JPS customer in good standing.

Any non-JPS customers wishing to participate must first establish a billing
record of at least 3 months. After this waiting period, JPS will decide on the
220
condition for inclusion of such recent/new customers.

The applicant must be the owner of the property where the generating facility
221
will be located or have the permission of the property owner.

Commercial customers: 100 kW AC gross system output.

Residential customers: 10 kW AC gross system output.

An aggregate cap of 2% of the utility’s highest demand peak during the first
two years of the pilot phase.

An assessment of the impact on the JPS network will be done at the end of the
period (May 2014) with a view to removing or expanding the cap as is deemed
223
appropriate by regulator.
218 219
222
The contract term is five (5) years, which term is renewable on terms to be agreed
224
between the parties and shall include any changes to applicable regulations.
http://www.our.org.jm/ourweb/sites/default/files/documents/sector_documents/soc_application_form_fina
l_0.pdf
216
http://www.myjpsco.com/business/net-billing/net-billing-faqs/
Intermittent Energy from Renewable Facilities up to 100kW, p. 5
217
Intermittent Energy from Renewable Facilities up to 100kW, p. 29
218
219
220
Ibid
221
Ibid
222
223
224
Ibid
103
Simplified
interconnection
procedures
System or meter
specifications

Jamaica has interconnection procedures for net billing that are simplified visà-vis normal power procurement and have standard procedures but also
significant bureaucracy as the utility, regulator and the Ministry must all
approve any application.

The general requirement is that a competitive tender procedure must be
followed for any utility purchase of electricity intended for distribution
through the national grid.

However, for small capacity additions from renewable generation as under
net billing, non-procurement process is followed with the Standard Offer
225
Contract.

A 3-page application form must be submitted that constitutes both the
application for licensing to supply energy and the application for
226
interconnection.

The utility must review and verify accessibility and feasibility in each case
before approval or rejection.

After system installation and submission of documentation the utility
performs a commissioning test before grid connection.

Installations will be allowed to exchange power with the national grid under a
227
net billing arrangement which involves the following meter requirements:
(a) The installation of up to two (2) meters at the premises where the
renewable energy facility is located. In the case of two meters, each
meter will measure energy flow in opposite directions. One meter will
account for flows from JPS to the customer premises and the other from
the generation facility at the customer premises to JPS. In the case of the
installation of a single meter, that meter will have the capability to
measure energy flows in both directions. It is up to the customer to
decide their preferred configuration.
(b) JPS will be responsible for the installation and maintenance of the meters.
225

For the system and interconnection, a number of component, protection,
earthing, cable and inspection requirements must be met by the customer.

Customers are required to install interconnection and generator disconnect
switches to facilitate interruption of energy from their generation facilities or
228
disconnection of the generation facilities.
Ibid p. iii, ’Abstract’
Net Billing Application Process High Level Summary available at
http://www.our.org.jm/ourweb/sites/default/files/documents/sector_documents/full_page_photo_0_net_bu
ilding_process.pdf
226
Intermittent Energy from Renewable Facilities up to 100kW, pp. 2, 6.
http://www.our.org.jm/ourweb/sectors/electricity/determination-notices/jamaica-public-service-companylimited-standard-offer - accessed 13 September 2013.
227
228
Ibid p. 11 at clause 2.8.12
104
No, a unit exported is considered equivalent to a unit imported regardless of the
time of use.
Customer billing
changes and/or any
compensation

The standard contract specifies the rate fixed by the regulator at which the
customer will sell energy to, and purchase energy from the national grid.
229
These rates will published in the newspapers from time to time.

The customer will pay the prevailing retail price for energy consumed from the
national grid as is applicable to the customer’s rate and class and the will
purchase the customer’s excess electricity at the “short run avoided cost of
230
generation” plus a 15% premium. This is calculated as:
(i) The system total monthly fuel cost (in month i) divided by
(j) The net generation (in month i) plus
(k) A 15% premium for energy supplied to the national grid.

In June 2012 this worked out to a net billing purchase price of JMD 18.42/kWh
231
(~USD 0.18 or KES 15.35/kWh), which was half or less of the average 2012
retail rate.

JPS will compensate participants in the net billing program as follows:
232
(a) Each month customers will be compensated for the energy supplied. This
money amount will be shown on the electricity bill as a credit.
(b) If after application of the credit, monies are still owed to JPS, then this
amount is to be paid by the due date.
(c) If after application of the credit, monies are owed to the customer, then
this money amount will be carried over to the next month’s bill.
(d) At the end of June and December every year, any credit balance on the
customer’s account will be paid in full by JPS.
As per above, any credits are carried forward for a period up to six (6) months at
which time any net surplus is paid for by the utility.

The price paid for units generated by net billing customers is the same as the
233
short-run avoided cost of generation plus a 15% premium, whereas for any
units consumed the customer continues to pay the full retail rate.

Net billing customers continue to pay the standard security deposit due under
229
Ibid p. 2 at clause1.2
230
Ibid pp. 7-8 at clause 2.6
Republic of Jamaica, Office of Utilities Regulation. 18 July 2012. Public Notice: Net Billing Purchase Price of
Energy for the month of June 2012.
231
232
http://www.our.org.jm/ourweb/sites/default/files/documents/sector_documents/30.9.11jpsco_standardoffercontract_-_determination_notice.pdf
233
105
JPS’s Standard Terms and Conditions of electricity supply to its customers,
which is an amount equal to the value of three (3) months electricity
235
consumption.
Other features
234
Ibid p. 10 at 2.8.9
235
Ibid p. 49 at clause 12.0
234

Applicants for net billing must also pay a non-refundable processing fee of
JMD 2,000 (~USD 21 or KES 1666) for residential and JMD 10,000 (~USD 97 or
236
KES 8,331) for commercial customers.

New meter equipment and installation costs are borne by the customer and
are recovered through the rates charged to the customer on their electricity
237
bill.

Customers may, with notice to the utility, have the net meter(s) tested by the
238
Bureau of Standards Jamaica at the customer’s cost.

In case the utility determines that a system impact study is needed, the cost
for such shall be borne by the customer.

JPS may disconnect the customer’s generation facility from the national grid
239
for non-payment of sums owing by the customer to JPS.

The customer is required to properly maintain the generating facility and
240
retain proper maintenance records.
236
Intermittent Energy from Renewable Facilities up to 100kW, pp. 2, 6.
http://www.our.org.jm/ourweb/sectors/electricity/determination-notices/jamaica-public-service-companylimited-standard-offer - accessed 13 September 2013.
237
238
Ibid, p. 10
239
Ibid p. 11 at clause 2.8.11
240
Ibid p. 9
106
A7.10
Brazil
Country 241
Size
8,514,877 sq km
Population
201,009,622 (2013)
GDP per capita
USD 11,340 (2012)
sector
Agriculture: 5.2 %
242
Industry: 26.3 %
Services: 68.5 %
Main industries
Textiles, shoes, chemicals, cement, lumber, iron ore, tin, steel, aircraft, motor
vehicles and parts, other machinery and equipment.
Installed capacity
106 200 MW (2010)
Electricity access
98.7 %
2,384 kWh/year(2010)
Generation
489,500 GWh/year (2010)
Grid mix
241
243
Technology
Oil
6.0%
Hydro
68.6%
Biomass
8.7%
Wind
1.7%
Gas
11.0%
Nuclear
1.6%
Coal
2.4%
Solar PV
0.0%
https://www.cia.gov/library/publications/the-world-factbook/geos/br.html
242
243
http://www.mme.gov.br/see/galerias/arquivos/Publicacoes/Boletim_mensalDMSE/Boletim_de_Monitorame
nto_do_Sistema_Elxtrico_-_Junho-2013.pdf
107
Peak load
Peak load: 69,757 MW
Time of peak: 17:00-22:00
T&D losses
Total loss on system: 17.5 % (2011)
Total interrupted load on national grid in: 45389 MW (97 interruptions) (2012)
price per customer
category
Tariff
USD/kWh (2011)
Residential
0.19 (KES 16.27)
Industrial
0.13 (KES 11.13)
Commercial
0.16 (KES 13.70)
Rural
0.12 (KES 10.27)
Public bodies
0.18 (KES 15.41)
Public lighting
0.10 (KES 8.56)
Public service
0.11 (KES 9.42)
Own consumption
0.18 (KES 15.41)
Sistema de Compensação de Energia
Resolução Normativa N º 482/2012
Effective date
17-Apr-2012
Resolução Normativa N º 517/2012, 11-Dec-2012
Incentive schemes
Solar power has 2 incentive schemes:

Tax benefits for solar power deployment

Discount in transmission and distribution usage charges = 80% for solar
systems < 30 MW during the first 10 years of operation
Achievements
n/a
Challenges
n/a
108
Item
Technology types
permitted
Wind, hydro, solar, biomass, cogeneration
Eligible customer
categories

All customer categories

However, “free consumers” (500 – 3000 kWh) and “special consumers” (>
3000 kWh) cannot take part in net metering.

Distributed micro-generation: ≤ 100 kW

Distributed mini-generation: 100 kW - 1MW

In both cases, this is further limited to the customer contract load or demand
except in special cases upon request
Maximum system size
No limit
Not explicitly stated
Simplified
interconnection
procedures
1) Issuing of Opinion on Access (30 days for micro, 60 days for mini)
2) Inspection (if requested by consumer, 30 days)
3) Delivery of inspection report (15 days)
4) Approval of interconnection point (7 days)
 Effective connection (82 days)
System or meter
specifications
The technical specifications of the meter are given in Procedimentos de
Distribuição de Energia Elétrica no Sistema Elétrico Nacional (Proceedings for the
distribution of electricity on the national electric system)
Yes, according to peak and off-peak tariffs.

The contracted tariff(s) remains valid.

The customer’s electricity bill must include information on any surplus
energy credit available that can be applied to the next billing cycling and, if
applicable, an indication of the credits that may expire in the next billing
period if not consumed.

Yes, up to 36 months: Any power supplied to the network which isn’t
accounted against consumption in the current period for the generator
having produced it or any other generators owned by the same firm/person
and serviced by the same distribution company, can be accounted against
consumption in subsequent periods. Surplus energy should be balanced out
in the same tariff period (i.e. peak or off-peak). In case this doesn’t take
place, the difference in tariffs should be respected.

Any generated power which is unused by the generator is supplied to the
109
local distribution network on “loan”. The generator is later compensated
with power from the same network at that specific generation unit or
another unit owned by the same firm/person (according to legal
registration).
Other features

A final possibility is the case in which ownership of two units isn’t legally the
244
same, but instead the two units have shared interests , they may still
transfer credits between the two units. This particular characteristic is
expected to enable community installations which share credits.

The cost difference between a net meter and the standard meter are
covered by the customer as well as the cost of meter installation.

Time of use tariffs are applied, meaning a unit credited can only be used to
displace a unit consumed of the same tariff value.

If any customer surplus credit is not consumed within the 36 month carry
forward period, the units will be forfeited to the distribution utility.

If there is any proven irregularity in the units consumed or exported in a
period, any surplus credits are forfeited.

In the case a net metering customer connected at the “primary” voltage has
exported surplus power metered at the “secondary” voltage only, any line
and transformer losses shall be borne by the customer.

On the other hand, the costs of any extensions or additions necessary on the
distribution network are to be borne by the distribution company.

Distribution companies must regularly collect data on net metering systems
and provide this to the regulator.

The net-metered customer is liable for any damage to the distribution
system proven to be caused by its distributed generator.
http://www.renewableenergyworld.com/rea/news/article/2012/07/brazils-attempt-at-distributedgeneration-will-net-metering-work
244
110
EUEI PDF is an instrument of the

the Final Net Metering Assessment Report Volume 2

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