Public Disclosure Authorized Innovative Approaches to PPPs ...

Innovative Approaches to PPPs for Smart Grids

Report to World Bank

August 2018

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Acknowledgements

Funding for this publication was provided by the Public-Private Infrastructure Advisory Facility (PPIAF). Established in 1999, PPIAF is a multi-donor technical assistance facility housed inside the World Bank Group. PPIAF is a global facility dedicated to strengthening the policy, regulatory, and institutional underpinnings of private-sector investment in infrastructure in emerging markets and developing countries. PPIAF catalyzes private participation through public-private partnerships (PPPs); market-based financing of sub-national entities; and by supporting the generation, capture, and dissemination of best practices relating to private-sector involvement in infrastructure. For more information, visit www.ppiaf.org.

Support by the Energy Sector Management Assistance Program (ESMAP) is gratefully acknowledged. ESMAP—a global knowledge and technical assistance trust fund program

administered by the World Bank that assists low‐ and middle‐income countries to increase

know‐how and institutional capacity to achieve environmentally sustainable energy solutions for poverty reduction and economic growth. ESMAP is governed and funded by a Consultative Group (CG) comprised of official bilateral donors and multilateral institutions, representing Australia, Austria, Denmark, Finland, Germany, Iceland, Lithuania, the Netherlands, Norway, Sweden, the United Kingdom, and the World Bank Group.

Acronyms and Abbreviations

ADR Automated demand response

ASP Ancillary Services Procurement Plan

BES Battery energy storage

CFE Comisión Federal de Electricidad

CREZ Competitive Renewable Energy Zones

DER Distributed energy resources

DGE Director General of Energy (in Cabo Verde)

DoE Department of Energy

ECG Electricity Corporation Ghana

ERC Energy Regulatory Commission

ESS Energy storage system

ETED Empresa de Transmisión Eléctrica Dominicana

EV Electric vehicles

IPP Independent Power Producer

kW Kilowatt

MENA Middle-East and North Africa

MHZ Mega Hertz

MW Megawatt

NCRE Non-conventional renewable energy

NDRC National Development and Reform Commission

NEPCO National Electric Power Company (Jordan)

NGCP National Grid Corporation Philippines

OATS Open Access Transmission Service

PGE Pacific Gas and Electric

PMUs Phasor measurement units

PO Purchase Obligations

PG&E Pacific Gas and Electric

PPA Power Purchase Agreement

PPP Public private partnership

PSP Private sector participation

PV Photovoltaic

R&D Research and development

RE Renewable energy

RTU Remote Terminal Unit

SCE Southern California Edison

SDG&E San Diageo Gas and Electric

SGIG Smart Grid Investment Grant

SME Small medium enterprises

VPP Virtual power plants

VRE Variable renewable energy

WESM Wholesale Electricity Spot Market

ZBM Zinc bromide module

Table of Contents

Executive Summary i

1 Review of Public Private Partnerships (PPPs) in Smart Grid Investments 1

1.1 Context 1

1.1.1 When is a grid smart? 1

1.1.2 Functional categories of smart grids 2

1.1.3 What is a PPP? 5

1.1.4 Opportunities for using PPPs in smart grid development 5

1.2 Recent Trends in Smart Grid Projects 6

1.2.1 Enhancing transmission and distribution grid reliability 7

1.2.2 Enabling dynamic integration and management of power sources 7

1.2.3 Enabling shaving of system peaks 8

1.2.4 Integration of consumer as a producer 9

1.3 Framework for Applying PPP Structures to Smart Grid Developments 9

1.4 Key Barriers to the Successful Adoption of Smart Grid Technology 14

1.4.1 Financial viability 14

1.4.2 Regulatory barriers 15

1.4.3 Regulatory barriers in developing countries 15

1.4.4 Technical specifications and market rules 16

2 Detailed Assessment of Smart Grid PPP Model Design and Implementation 18

2.1 Selection of the Short List for Case Studies 18

2.2 What Specific Outputs (Services) Should Smart Grid PPPs Deliver? 23

2.2.1 System stability services from battery storage providers 23

2.2.2 Coordinated and automated demand response by mid-size commercial customers 24

2.2.3 Virtual power plant business model 24

2.2.4 Energy storage system integration to manage system peaks and increase reliability 24

2.3 Lessons Learned from the Case Studies 25

2.4 PPP Structure Considerations 26

3 Categorization of Relevant Smart Grid PPP Models 28

3.1 Ancillary (System Stability) Services from Battery Storage Providers: Masinloc, Philippines AES/NGCP Project 28

3.2 Coordinated and Automated Demand Response by Large Commercial Customers – California Honeywell Projects 31

3.3 Virtual Power Plant Business Model 35

3.3.1 What are the key contractual terms? 37

3.3.2 Penalty and reward regime 38

3.3.3 Technical specifications 38

3.4 Distributed Energy Storage System Integration to Manage System Peaks and Increase Reliability - Upper Hunter Region, Australia 38

3.5 Smart Meter Technology Roll-Outs in Mysuru, India and Mexico 40

4 Recommendations for Application of PPP Models 43

4.1 System Stability Services from Battery Storage Providers 43

4.1.1 Structure of the model 44

4.1.2 Technical requirements 46

4.1.3 Risk allocation and financing 46

4.2 Coordinated and Automated Demand Response Model 47



4.2.3 Risk allocation 49

4.3 Virtual Power Plant Model 50



4.3.3 Risk allocation 52

5 Opportunities for Smartgrid PPPs in Developing countries 53

5.1 El Salvador 54

5.2 Dominican Republic 55

5.3 Other Caribbean Islands 56

5.4 Ghana Error! Bookmark not defined.

5.5 Jordan Error! Bookmark not defined.

5.6 Kenya 58

5.7 Morocco Error! Bookmark not defined.

5.8 Cabo Verde Error! Bookmark not defined.

Appendices

Appendix A Overview of Global Smart Grid Experience relevant to Development of PPP Arrangements 65

Tables

Table 2.1: Short List Assessment 21

Table 5.1: SGIG Merit Review 72

Table 5.2: AEEG Smart Grid KPIs 73

Figures

Figure 1.1: Optimal Conditions for Smart Grid PPPs in Developing Countries 10

Figure 1.2: Schematic Illustration of Utility and Regulatory Reform 11

Figure 3.1: Masinloc BES 29

Figure 3.2: Contractual Arrangements Between Key Stakeholders 32

Figure 3.3: Jeju Island VPP Test Bed 36

Figure 3.4: Contractual Agreements Between Key Stakeholders 39

Figure 4.1: Summary of System Stability Services Model 45

Figure 4.2: ADR Model Summary 48

Figure 4.3: VPP Model Summary 51

Figure 5.1: Share of RE to total electricity producedError! Bookmark not defined.

Figure 5.2: RE Production and Planed RE Production (MWh/year) 56

Figure 5.3: Generated Electricity in Morocco by Technology Share, 2013 (percent) 61

Figure 5.4: Electricity Production in Jordan by Type of Fuel (2007 to 2014) 62

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Executive Summary

The purpose of this report is to identify how public private partnerships (PPPs) could be used in developing countries to enable and promote smart grid technology investments.

The information and communication technology that underpins smart grid technology is advancing at pace. High speed internet connections enable immediate communication between energy consumers, utilities and generators. This is occurring in developed and increasingly in developing countries. The technology not only enables greater efficiencies (doing more with the same fixed investments) and reliability but has the potential to be particularly useful in addressing electricity sector challenges specific to developing countries.

Smart grid technology has the potential to play an especially important role in managing the variability and complexity that are inherent in variable renewable energy (VRE) and distributed energy resources (DERs).1 Smart grid technology is therefore an essential part of managing climate change transitions. VRE and DERs are dominating new power capacity in the world. Almost two-thirds of global net new power capacity in 2016 was from renewable sources.2 Much of that additional capacity is being built in developing countries. Technology costs for VRE and DERs are falling rapidly, particularly for solar PV. Smart grid technology investments therefore are growing in importance in step with this global trend.

There are already numerous examples of electricity utilities in the developing countries investing in smart grid solutions. However, the pace of such investment is constrained by the financial and regulatory challenges facing many developing country utilities. In addition, private sector service providers can bring capacity and technological expertise to modernization of energy infrastructure. This report examines existing experience with private sector participation in the provision of smart grid services and considers how it can be scaled up in developing countries.

Conditions for PPPs and smart grids

PPPs can enable a private party to provide power services under a contractual framework where risk and management responsibility is largely transferred to the private party in exchange for a financial return. In principle, the services that smart grid technologies can provide, should be able to be delivered under a PPP model. Several criteria need to be fulfilled:

▪ Outputs that can be clearly specified, measured, and enforced

▪ Private sector incentives over lifecycle of activity create value for money. This is the case where the private sector partner can offer:

– Expertise in delivery

– Innovation where incentive exists to do so

– Efficiency gains when compared to public sector provision

1 DERs generally include small-scale energy generation and storage sources connected to the distribution (rather than

transmission) and, as a result, located close to load centres. DERs often draw on renewable sources. Solar

photovoltaics, wind and battery storage energy sources are included in the definition.

2 International Energy Agency (2017), Market Report Series Renewables 2017: Analysis and Forecasts to 2022, available at: https://webstore.iea.org/market-report-series-renewables-2017

https://webstore.iea.org/market-report-series-renewables-2017

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▪ Benefits outweigh the transaction costs, and benefits of alternative delivery models such as conventional procurement

Private financing that comes with PPPs is usually the least important part of PPP contracts. Private finance can be an advantage where a public-sector borrower is a poor creditor.

Framework for applying PPP structures to smart grid developments

The report diagnoses the preconditions necessary for optimal deployment of PPP projects in developing countries that could deliver smart grid technology services. Figure 1.1 below illustrates the high level optimal conditions. These include the level/stage of electricity sector reform, the operational scope of the relevant utility where smart grid technology might be deployed, and conditions where long-term contracts with private service providers are possible.

Figure 1.1: Optimal Conditions for Smart Grid PPPs in Developing Countries

There are some forms of smart grid technology that are less suitable to outsourcing through a PPP-style performance contract, either because the use of the technology has to be integrated into the core management of the utility, or because the technology is just too experimental at this stage and not yet ready for implementation through standardized business models. However, for those types of smart grid technology that can be implemented through PPP contracts, the conditions for implementation in essence are that:

▪ The power sector is sufficiently reformed that private sector participation is possible at least on the wholesale side, and

▪ The off-taker is sufficiently credit worthy.

The distinction that is drawn between the technologies that are ready for implementation through PPP contracts and those that are not has important implications for interpreting conditions for implementing smart grids. In essence, immediate implementation of some forms of smart grid solutions through PPPs is possible in any electricity sector that is already open to IPP contracts. However, as other technologies mature, further regulatory and structural reforms may also enable those solutions to be implemented through PPP contracts.

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Barriers to adoption of smart grid technology

Despite the opportunities for smart grid technologies, several barriers exist delaying their deployment. Financing difficulties emerge where novel technology is perceived as risker than existing conventional methods. Electrical system regulatory rules can actively disincentivize new investment in efficiency-enhancing technology. This can be a barrier to any smart grid technology introduction but can also simply limit the incentives to use all the features of a technology. Regulatory regimes were often designed for conventional grid systems. Regulatory barriers unique to developing countries include legacy regimes, lack of independence and tariff structures that do not reflect costs. Rigid technical specifications, market rules and issues such as cybersecurity concerns also present barriers. Finally, technical barriers exist. These include relatively high (albeit constantly falling) cost of new technology and a lack of capacity in and experience with operating and managing the technology. An absence of reliable communications networks can hinder integration of new smart grid power assets.

Smart grid case studies

This study did not identify any smart grid projects where the key characteristics of a PPP were satisfied. There are many co-investment or partnership relationships between public utilities and private sector companies, which are often referred to as PPPs in the relevant documentation. However, these have more in common with procurement or technology trials than conventional PPPs. Many examples were partially government-sponsored test bed or investigative trials.

Short-listed case studies

This report identifies a number of technical, commercial and regulatory elements that can be packaged together into a replicable PPP model for the roll out of some specific smart grids technologies. In particular, PPP models appear to provide a good basis for using smart grid technology to address the issues of integrating variable renewable energy into the electricity grid. Another promising application is the use of batteries to provide rapid-response ancillary services.

In order to inform the creation of replicable PPP models, this report examined the following case studies in close detail:

▪ Procurement by the National Grid Company of the Philippines of reactive power and other ancillary services from distributed battery storage. This report focuses specifically on the existing contract between NGC and AES Power (recently purchased by San Miguel Corporation) for the provision of 20MW of storage in South Luzon. While this specific contract is procured in the context of the need to stabilize the Filipino energy-only market, the procurement model, both in terms of performance specifications, funding structure and private financing was considered to represent a replicable example suited to different market models.

▪ Procurement of distributed battery storage to manage distribution system peaks and security of supply in Australia. Again, it is possible to replicate this model in different markets with different regulatory and market structures. A key advantage of this example is that the private operator is required to deliver outputs which are not dependent on the performance of the utility within which the contract is embedded. While Ausgrid is a well performing utility, the same results can be achieved within a poorly performing utility.

▪ USA turnkey automated demand response project. This is an interesting example where a private operator is contracted to implement a comprehensive

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set of technical and contractual solutions that deliver customer demand response. This example can potentially be replicated in different market settings, with the performance of the private contractor not dependent on the quality of the utility and other participants in the market.

▪ South Korea Jeju Island Virtual Power Plant business model. The VPP model represents a very promising PPP structure that can be rolled out within different market settings and does not rely on the advanced infrastructure or the quality of performance of the incumbent utility. The Jeju Island business model represents a set of technical requirements, communication protocols and standardized commercial terms that could serve as a useful model of PPP contracts.

While none of the case studies represent off-the-shelf models that can be directly replicated in all developing countries, the case studies present structural ideas that would enable PPP models which could work under certain circumstances.

Recommended models for smart grid PPPs

The general theme that emerges from the case studies is that PPP models for smart grid technologies need to provide utilities with straight-forward and reliable solutions, transferring the management of technological complexity to the private sector. In particular, smart grid PPPs are best placed to solve the issues posed by VRE, presenting the utility with reliable net supply of energy while using private sector incentives and the ability to finance new technology to manage the variability. In a sense, the proposed smart grid models would appear to the utility as largely indistinguishable to conventional dispatchable IPPs.

To turn examples into workable models that can be applied in developing countries, PPP models must have risk allocations which are consistent with the capabilities and expectations in developing countries. Developing country utilities generally expect dispatchable energy with high degree of reliability and have limited internal capacity to manage variability. Hence, the proposed smart grid PPPs focus on how the entire risk of managing variability can be transferred to the private sector. In addition, commercial arrangements under the PPP contracts—such as the relationship between a VPP operator and owners of VRE resources discussed below—can correct for poor regulatory incentives and the absence of efficient tariffs. For example, a VRE operator can internally remunerate its participants on time-of-use basis even if the utility does not have time-of-use tariffs.

Nowadays VRE projects represent two thirds of all investment in new electricity generation capacity, and much of that investment is taking place in developing countries. Many developing countries have now achieved sufficiently high VRE penetration rates that they require innovative solutions to ensure system stability. In other countries), the uptake of VRE has been unnecessarily slowed down by the technical conservatism of the grid operator. In all cases, urgent need exists to bring in innovative technology, private finance and private incentives to manage the complexity of VRE integration.

Like the existing IPP contracts in developing countries, these PPP models will face issues of credit worthiness of offtakers. The same approaches as are currently used for credit enhancement in markets with IPPs should be adopted. For example, the use of partial risk guarantees by IFIs and other credit enhancement measures could be targeted at smart grid PPPs with the objective of maximising the uptake of VRE.

This report proposes at the conceptual level three archetype PPP models for smart grids implementation:

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▪ Provision of electricity system stability services by third party battery storage providers. It is important to note that battery services contribute to increased energy access in two ways: while they enable increased penetration of VRE, the energy supplied to maintain system stability also adds to the overall available energy to meet increasing demand. A variation on the proposed model would involve a combination of VRE and storage, to combine additional energy capacity with contribution to system stability.

▪ Provision of coordinated and automated demand response by third party aggregators and technology service providers

▪ Provision of Virtual Power Plant (VPP) services which combine storage, distributed generation and automated demand response.

Opportunities for smart grid PPPs in developing countries

The final section of this report examines the possible opportunities to deploy smart grid technology under the archetype PPP models. Countries are studies where the power sector has undergone some reform, so that private sector participation is possible, the utility is creditworthy and there is some experience in procuring from IPPs. A further consideration is where intermittency issues arise (or are likely to arise) due to uptake of VRE. The countries examined are El Salvador, Dominican Republic, a number of Caribbean island countries, Ghana, Kenya, Cabo Verde, [Senegal], Morocco and Jordan.

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1 Review of Public Private Partnerships (PPPs) in Smart Grid Investments

1.1 Context

The purpose of this report is to identify how public private partnerships (PPPs) could be used in developing countries to enable and promote smart grid technology investments.

The information and communication technology that underpins smart grid technology is advancing at pace. High speed internet connections enable immediate communication between energy consumers, utilities and generators. This is occurring in developed and increasingly in developing countries. The technology not only enables greater efficiencies (doing more with the same fixed investments) and reliability but has the potential to be particularly useful in addressing electricity sector challenges specific to developing countries. For example, smart meters are increasingly being rolled to address non-technical system losses.

Smart grid technology has the potential to play an especially important role in managing the variability that is inherent in variable renewable energy (VRE) and distributed energy resources (DERs). Smart grid technology is therefore an essential part of managing climate change transitions. VRE and DERs are dominating new power capacity in the world. Almost two-thirds of global net new power capacity in 2016 was from renewable sources.3 Much of that additional capacity is being built in developing countries. Technology costs for VRE and DERs are falling rapidly, particularly for solar PV. Smart grid technology investments therefore are growing in importance in step with this global trend.

There are already numerous examples of electricity utilities in the developing countries investing in smart grid solutions. However, the pace of such investment is constrained by the financial and regulatory challenges facing many developing country utilities. In addition, private sector service providers can bring capacity and technological expertise to modernization of energy infrastructure. This report examines existing experience with private sector participation in the provision of smart grid services and considers how it can be scaled up in developing countries.

1.1.1 When is a grid smart?

Smart grids comprise numerous technologies that integrate electricity and digital communication networks and address different aspects of power system operations. The term does not refer to any specific function or typology of electricity network component, rather it encompasses a range of technologies. Smart grids deliver energy efficiency benefits by allowing for:

▪ More sophisticated monitoring of and response to the performance of the transmission and distribution networks

▪ More flexible integration of multiple generation and energy storage sources, in particular variable renewable generation

▪ Two-way communications between the utility and its assets, suppliers and customers that allows customer response and own energy production to be fully incorporated.

3 International Energy Agency (2017), Market Report Series Renewables 2017: Analysis and Forecasts to 2022, available

at: https://webstore.iea.org/market-report-series-renewables-2017

https://webstore.iea.org/market-report-series-renewables-2017

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Electricity grid technology evolves continuously, improving efficiency and quality. The term “smart grid” means more than such continuous improvements in efficiency and quality in electricity grid technology. Rather, it refers to the qualitative change in how power systems are operated. Smart grids are a recent development of complementary technology that permit sophisticated monitoring and response, flexible integration of generation and storage, communications between utilities and network.

This report identifies stand-alone projects where smart grid technology has led to significant step-changes to the operation of power systems. These projects go beyond the improvements that accompany incremental changes to networks, whether they be regulation- or technology-driven. Rather, they are deliberate choices to adopt ‘smart’ technology for the purpose of materially advancing a power system.

1.1.2 Functional categories of smart grids

Smart grid technologies broadly fall into the following functional categories:

▪ Reliability of transmission and distribution networks. Smart grid technologies allow faster diagnosis of distribution and transmission outages and automated restoration of the undamaged portions of the grids. For this function, smart grids rely on improved real-time measurement of electric waves (through phasor measurement units) which presents a comprehensive picture of the network, and equally real-time automated re-routing and isolation of the affected parts of the network. Smart grid’s diagnostic and self-healing capability prolongs the life of the infrastructure and minimizes disruption for customers

▪ Dynamic integration and management of power sources. Smart grid technologies—through improved information flows—allow for more flexible and decentralized management of different power sources on the network than is possible through the conventional centralized system operator data capture. This allows for flexible balancing of demand and supply across different parts of the network (rather than just within clearly defined transmission and distribution nodes) and facilitates integration of distributed variable renewable generation sources in a way that contributes to, rather than challenges, the stability of the network.

A key aspect of such technologies is that they can both be used to upgrade integrated system operation and provide a service to the conventional system operator. A virtual power plant (VPP) is a portfolio of distributed generators and sheddable demand controlled in such a way that the VPP is able to deliver reliable power to the grid. A VPP uses smart grid technologies to solve the problem of renewable energy variability through aggregation, while appearing as a conventional “dispatchable” plant to the system operator

▪ Integration of Cloud Computing technology to smart grids. Smart grids require reliable and secure computing communication systems. Once such systems are created for communication purposes, they also enable cloud computing. Cloud computing permits on-demand network access via a shared pool of configurable computing resources. Servers, networks, storage and applications can be rapidly provisioned from the ‘cloud’ enabling access to big data and helping grid participants to interact with one another. The ‘cloud’ links energy consuming devices to the grid, DERs and utilities

▪ Shaving of demand peaks on the networks. A number of smart grid technologies contribute to lowering demand peaks. A flat load curve reduces the cost of transmission and distribution infrastructure, as well as reducing the

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need for high-cost peak generation. This functional category can be broadly divided into three elements:

– Enabling consumer response to pricing incentives through smart meters.

– Installation of equipment on consumer premises that enables remote control of on-site appliances to enable demand response (DR) solutions.

– Installation of distributed and grid connected battery storage to manage system peaks.

Technologies that enable the shaving of demand peaks more generally enable increased energy efficiency.

▪ Enabling of consumer-producer integration. Conventional networks integrated consumer-site generation (e.g. through solar panels) by netting out such production from load. Smart grids enable consumers to sell their decentralized excess production into the grid as well as to sell the services of customer-owned behind-the-meter storage devices and become “prosumers”. Integration of plug-in electric vehicles (EVs) represents a special case of consumer-producer involvement. In this case, consumers—owners of electric vehicles—place new demands on the network through the need to access specialized fast charging infrastructure and through the influence of their charging decisions on the load profile. Similarly, EVs represent distributed energy storage that can be used to balance the system as required.

▪ Cybersecurity. This is an over-arching functional requirement. The deeper the reliance on smart grid technologies—and hence on data flows—the greater the vulnerability of a power system to malicious attack, fraud, loss or corruption of data. Increased integration of consumers into the operation of the power system will also create privacy concerns as well as issues about ownership and control of information. All of these issues need to be addressed to make any aspect of smart grid acceptable and useful to its various stakeholders.

▪ Blockchain. Distributed ledgers or blockchains will further facilitate the ability of participants in electricity distribution grids to transact with one another without intermediation (peer to peer tranactions). Traditional electricity grids have clear demarcations between producers, distributors and consumers. A future smart grid is likely to see consumers also act as producers and buy and sell energy with each other. A distributed ledger or blockchain records transactions in a decentralized manner. It stores information in a cryptographically secure way and does not need to rely on a centralized authority. Thus, consumers and producers in a future smart grid need not rely on the central utility for verification of transactions on the grid.

There are clearly important overlaps between various functional categories. For example, efficient vehicle-to-grid connection, enabling injection of power from car batteries into the grid during peak times as well as to support isolated parts of the grid during outages, combines the functions of enabling consumer-producer with the broader functionality of the self-healing grid, as well as dynamic management of power sources. Similarly, to ensure that EVs are charged at times of lowest demand or during peak wind or solar power, there will be a need for combining cloud computing and data analytics software with efficient pricing incentives and smart metering infrastructure.

However, broad functional categorizations are useful for a number of reasons:

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▪ Different jurisdictions and power systems may focus on different objectives, and hence seek specific functional outcomes from smart grid implementation that address their particular needs

▪ Different functional elements of the overall smart grid concept can be integrated on a stand-alone basis. In fact, the experience to date suggests that the implementation of smart grid technologies tends to proceed through functionally defined “projects”, rather than as integrated implementation

▪ Different functional categories impose different demands on market structure, market design and the regulatory environments. For example, smart grid technologies designed to enable demand response require comprehensive introduction of time-of-use pricing, either through regulation or through market reforms that enable competitive wholesale price-setting

▪ Well-performing PPP arrangements require precise definition of performance outputs. Such outputs follow functional categories. As a result, practical examples of PPP arrangements are expected (and indeed observed) as falling within the above functional categories. To put it simply, PPP arrangements can be expected to divide the overall program of converting conventional grids into smart grids into “bite-sized” manageable chunks.

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1.1.3 What is a PPP?

Broadly defined, a “Public-Private Partnership” (PPP) is:4

A long-term contract between a private party and a government entity, for providing a

public asset or service, in which the private party bears significant risk and management

responsibility and remuneration is linked to performance.

PPPs can involve provision of new assets and services, or the management of existing assets and services. They can include PPPs in which the private party is paid entirely by the final users of the service (for example, user-pay PPPs), by a government agency (for example, government-pay PPPs), or a combination of the two. It can also mean contracts in which the private party performs a range of functions—provided significant risk and management responsibility has been transferred.

For the purposes of this report, a PPP is defined as a specific contractual model that requires a private party to finance, implement and deliver a clearly specified “smart grid” output in return for payment from the public agency.

1.1.4 Opportunities for using PPPs in smart grid development

Harnessing PPP contracts in smart grid development depends on a number of pre-conditions being met. Smart grid projects that could be considered for a PPP must have the following characteristics:

▪ Outputs that can be clearly specified, measured, and enforced. This means that the measure of ‘success’, must be defined on a stand-alone basis. Outputs must be able to be measured and the private sector PPP partner held accountable for the output.

Outputs that do not lend themselves to clear specification and measurement are difficult to incorporate into a PPP framework.

▪ Private sector incentives over lifecycle of activity create value for money. PPP is the preferred solution when it is preferable to procure a service from the private sector, rather than simply procuring equipment. Involving the private sector may result in efficiency gains and improved performance, for the following reasons:

– Expertise: on-going provision of expertise through the delivery of services

– Innovation: procurement of PPPs can allow the private sector to offer innovative solutions and delivery options (this form of innovation should not be confused with technological innovation: the public sector can always purchase the latest technology directly). However, private parties will need to be incentivized for these benefits to materialize

– Efficiency: The private sector, if incentivized appropriately, is generally more efficient than its public counterparts. Involving the private sector will likely lead to lower project costs.

▪ Benefits outweigh the transaction costs and alternative delivery models

– While involving the private sector can add value, it is important to ensure that the benefits outweigh the costs of entering into a PPP transaction. The alternative to PPP is generally conventional procurement and public sector

4 World Bank, (2017). Public-Private Partnerships: Reference Guide Version 3. World Bank, Washington, DC.

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management of the asset or service. The costs of a PPP transaction can be significantly more than conventional procurement.

– PPP procurement processes are costly, especially as significant investment by a government is necessary in the early stage. The initial stage is critical, as this is where the public sector must draft the PPP contract and has the most leverage to use competitive tension between bidders to optimize how the bidders will promote the project outcomes.

– It is advisable to carefully carry out the pre-feasibility study and feasibility study (including an analysis of risks, preparation of financial plans and analysis of fiscal responsibility) prior to beginning the procurement. Once procurement has begun, an intensive period of engaging with potential bidders, issuing an RFP and negotiating contracts begins.

– During the lifetime of the PPP, the public sector party must manage the contract and monitor outcomes, to ensure the private party meets its obligations.

▪ Private financing that comes with PPPs is usually the least important part of PPP contracts. For the private sector to be able to raise finance, PPP contracts will need to ensure sufficient revenue and the creditworthiness of the public counterparty to the contract. Hence, it is not an easy way to raise finance. In many cases, government or donor funding may also be available, which is materially cheaper than private financing. There is already considerable experience with IPP contracts in developing countries and there is deep understanding that such contracts are often not possible without credit enhancement. For example, in Africa—where there are significant unmet electricity needs—numerous good-quality renewable generation projects are not able to proceed due to poor credit worthiness of off-takers. The same issues will affect smart grid PPP projects. As discussed later in the report, the risk allocation under practicable smart grid PPP projects is likely to be similar to existing IPPs, and hence such projects will face similar financing challenges.

1.2 Recent Trends in Smart Grid Projects

There is limited global experience with applying PPP structures to the implementation of smart grid projects. An extensive review of projects around the world has revealed that there are no off-the-shelf models that can be easily replicated. To date, there have been very few relevant examples of PPPs or similar contractual arrangements being used to implement smart grid technologies. The survey of recent experience around the world is presented in Appendix A.

There are a number of reasons for this. First, many types of smart grid developments are in early stages of technology trials. The public sector is often involved, but in the form of providing support for research and development (R&D), rather than clearly procuring solutions to specific problems. In many cases, the public sector has funded test-bed programs or trials to catalyze investment in smart grid technology. In many instances, the private sector participates in such trials on a “venture” basis, aiming to prove the technology rather than to provide specified services on a clear contractual basis.

Second, many smart grid technologies relate to the core operation of the grid. While technology and equipment are procured from private suppliers, grid operators often prefer to internalize the operational aspects of implementing smart grid technologies.

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This section sets out the survey findings around the recent trends in this sector for each functional category of possible smart grid project.

1.2.1 Enhancing transmission and distribution grid reliability

Smart grid technologies can enhance transmission and distribution grid reliability. This form of the technology has the biggest share of what can be termed “smart grid”.

The particular technology that enables enhanced transmission grid reliability is based around synchrophasor technology. This allows faster diagnosis of distribution and transmission outages and automated restoration of the undamaged portions of the grids. For this function, smart grids rely on improved real-time measurement of electric waves (through phasor measurement units or PMUs), which presents a comprehensive picture of the network, and equally real-time automated re-routing and isolation of the affected parts of the network. PMUs rapidly measure voltage, current and frequency parameters, convert these into phasor values with a time stamp. These values are then communicated back to the utility or grid operator to diagnose.

The principal benefit of synchrophasors is the ability to rapidly and immediately diagnose issues in the grid. This leads to a ‘self-healing’ capability which prolongs the life of the infrastructure, as well as lower costs of grid failures and disruption for customers.5

Numerous countries have implemented smart grid measures to enhance reliability of grids. The majority of projects are characterized by close government involvement. In China and developing countries, where there is close association between the government, grid operators and the utilities, smart grid support has involved direct investment and support for PMU roll-out. In developed economies, support for grid reliability measures has been in the form of subsidy, R&D investment or direct support for test-bed projects to catalyze other private sector investment.

1.2.2 Enabling dynamic integration and management of power sources

Smart grid technologies can also better integrate and manage power sources in a dynamic way. Such dynamic management is becoming increasingly necessary given the recent developments in generation technology.

Developments that coincide with smart grid technologies include a rise in renewables, rise in distributed storage and generation, and increased use of virtual power plants (VPPs).

Smart grid technologies enable these new developments to function by improving communication and information flows between different parts of the grid and the various power generators. It is a significant improvement on conventional centralized system operator data capture. Improved communications enable the use of cloud computing as an additional layer that can accelerate integration of different parts of the smart grid by using data analytics and artificial intelligence solutions, including elements of cybersecurity. Cloud computing eliminates geographical boundaries and hence would provide developing country utilities access to the same tools that are available to the utilities in developed countries.

Rise in renewables

By their nature, solar and wind renewable sources are difficult to predict and variable, and as a consequence, they are not considered as dispatchable by operators. Hydro generation is also affected, but with more predictability, by natural phenomena. Furthermore, the way

5 Department of Energy, (2013), Synchophasor Technologies and their Deployment in the Recovery Act Smart Grid

Programs, available at: https://www.smartgrid.gov/files/Synchrophasor_Report_08_09_2013_DOE_2_version_0.pdf

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of supplying power around the world is changing and a greater reliance is placed on diversifying the energy-mix of countries by adding more renewables and as a result dynamic and responsive integration of these sources is needed.

Renewable sources (VREs) benefit from feed-in tariffs in numerous countries (although and renewable energy auctions are becoming more common). However, utilities can often deny obligations to pay these tariffs or are reluctant to hold auctions where renewable sources do not meet technical timeliness or reliability standards due to their inherent variable qualities. Smart grid integration and management technology can overcome these functional barriers. These are overcome through aggregation of diverse resources, thereby reducing the overall variability. For example, VRE can be combined with ADR and other less variable generation types. The improved information flows from smart grid technology is critical to facilitate this.

Rise in distributed storage and generation

Distributed storage and generation has grown in parallel to the technological shift to renewables. Distributed generation refers to the production of useful energy near or at the location of its use. Technological solutions include solar photovoltaic (PV) and storage, biomass, biogas, but also diesel generators. Where these distributed energy resources join a grid, smart grid technologies can become useful for coordinating their input.

Virtual power plants

Smart grid technologies—through improved information flows—allow for more flexible and decentralized management of different power sources on the network than is possible through the conventional centralized system operator data capture. This allows for flexible balancing of demand and supply across different parts of the network (rather than just within clearly defined transmission and distribution nodes) and facilitates integration of distributed variable renewable generation sources in a way that contributes to, rather than challenges, the stability of the network.

A key aspect of such technologies is that they can both be used to upgrade integrated system operation and provide a service to the conventional system operator. A virtual power plant (VPP) is a portfolio of distributed energy resources and curtailable demand controlled in such a way that the VPP is able to deliver reliable power to the grid. A VPP uses smart grid technologies to solve the problem of renewable energy variability through aggregation, while appearing as a conventional “dispatchable” plant to the system operator.

1.2.3 Enabling shaving of system peaks

Smart grid technologies can enable the shaving of demand peaks. Transmission and distribution infrastructure has traditionally been built to tolerate large peaks in demand. With a flatter load curve (that is, a lower peak relative to average daily load), the investment in transmission and distribution infrastructure can be reduced, and investment in additional capacity can be deferred or reduced in scope. A further advantage of a flatter load curve is a reduction in the need for short-term peak generation capacity, which is generally the most expensive (and often carbon intensive) generation form. This more generally enables increased energy efficiency.

Technology that shaves system peaks can be broadly divided into three elements:

▪ Enabling consumer response to pricing incentives through smart meters. Smart meters are a straightforward technology solution that provides the consumer with greater visibility of consumption and corresponding price, enabling the consumer to optimize consumption from simple to very

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sophisticated ways. This is only possible if the relevant electricity rate structure or tariff is responsive to demand peaks.

▪ Installation of equipment on consumer premises that enables remote control of on-site appliances. This technology enables utilities and/or grid operators to manage consumption across the grid, either directly or via an aggregator company.

▪ Installation of distributed and grid-connected energy storage systems (ESSs) to manage system peaks. Energy storage systems (ESSs) located at or close to the point of end-use consumption are increasingly being used to manage system peaks and increase reliability. These systems charge during off-peak periods and discharge at the peak in order to reduce the load, and therefore the difference between peak and average consumption. This reduces the level of investment required and makes the grid more reliable. ESSs are not new technology, however, their deployment in a distributed way, among multiple end-users is part of recent smart grid developments. Distributed ESSs are growing rapidly in use in developed countries, with front-of-meter ESSs doubling in use in the United States and forecast to grow to 3.3 Gigawatt by 2020.6

1.2.4 Integration of consumer as a producer

Traditionally, consumers of electricity in conventional grids have been just that; passive consumers of load. Historically, electricity was produced by large-scale high-voltage generators and distributed throughout the high-voltage grid, and then through local transformers and local low-voltage grids. With the rise of photovoltaic (PV) systems at residential or small commercial premises, a much wider range of consumers are becoming load producers in the grid. As electric vehicles increase in popularity, their more widespread use as a store of energy that can be discharged at peak times will also lead to the consumer acting more as a producer. Behind-the-meter generation (for example, residential PV) will also increase this.

1.3 Framework for Applying PPP Structures to Smart Grid Developments

As of May 2018, a survey of international examples of implementation of smart grid technology did not reveal any “pure” smart grid PPP projects that could be easily replicated in developing countries at scale.However, there are few examples that could be drawn upon that fulfill a majority of the criteria for PPPs. Most of the examples were partially government-sponsored test bed or investigative trials.

In fact, there are a range of conditions and policies in developing countries that there are required to enable optimal deployment of smart grid PPPs. These include the adequate level of liberalization of the regulatory framework in the power sector, the operational scope of the relevant utility where smart grid technology might be deployed, and conditions where long-term contracts with private service providers are possible.

As explained later in this report, there are some forms of smart grid technology that are less suitable to outsourcing through a PPP-style performance contract, either because the use of the technology has to be integrated into the core management of the utility, or because the technology is just too experimental at this stage and not yet ready for implementation through standardized business models. However, for those types of smart

6 U.S. Energy Storage Monitor: 2017 Year in Review and Q1 2018 Executive Summary, available at:

http://www2.greentechmedia.com/ESM17YIR#gs.48846zY

http://www2.greentechmedia.com/ESM17YIR#gs.48846zY

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grid technology that can be implemented through PPP contracts, the conditions for implementation in essence are that:

▪ The power sector is sufficiently reformed that private sector participation is possible at least on wholesale side, and

▪ The offtaker is sufficiently credit worthy.

The distinction that drawn between the technologies that are ready for implementation through PPP contracts and those that are not has important implications for interpreting conditions for implementing smart grids. In essence, immediate implementation of some forms of smart grid solutions through PPPs is possible in any electricity sector that is already open to IPP contracts. However, as other technologies mature, further regulatory and structural reforms may also enable those solutions to be implemented through PPP contracts.

Figure 1.1 illustrates high level optimal conditions. However, while the broad themes are helpful in screening out those jurisdiction that are least likely to have the conditions in place for a successful smart grids PPP, detailed analysis of each particular market would be needed to confirm that a smart grid PPP contract is possible.

Figure 1.1: Optimal Conditions for Smart Grid PPPs in Developing Countries

A regulatory framework with adequate level of liberalization must be in place to enable Smart Grid PPP contracts

The performance of any electricity sector is driven by two key factors:

▪ The quality of corporate performance of the utilities operating in the market, and

▪ The quality of the regulatory regime which sets the parameters for market participants and governs the commercial relationships and coordination between them.

In many countries—and certainly in most developing countries—the provision of electricity started through vertically integrated public utilities. The reforms since the 1980s have focused on:

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▪ Breaking up vertically integrated utilities, privatizing the existing operations to improve governance and enhance access to capital, and allowing entry of new private participants

▪ Creating a regulatory and market framework that provides external economic regulation of monopoly components of the power sector, while enabling competition and trading in non-monopoly elements. This includes either competitive procurement of energy by distributors or creation of competitive wholesale and retail markets.

Figure 1.2 illustrates this general concept. At one end of the spectrum, there are countries with fully reformed utilities and regulatory regimes (represented by the blue dot). In such countries, electricity services tend to be provided by private companies operating within an explicit regulatory regime and competitive markets. At the other end are jurisdictions where the reform process has barely begun and the sector continues to rely on vertically integrated public entities operating without external oversight (red dot). Remaining countries generally fall in between these two points. The dashed line oval represents the general spectrum of utility reform, performance and regulation.

The green oval represents a conceptual “sweet spot” for smart grid PPPs. On the utility performance axis, there is room for improvement, but the utility is not so advanced and commercially incentivized that it would secure the necessary smart grid services from its internal investment and resources. On the regulatory quality axis, some basic degree of reform is already in place, so that the system can in principle accommodate private sector participation (PSP), but some contractual solutions are required to incorporate a novel service offering under a smart grid PPP.

Figure 1.2: Schematic Illustration of Utility and Regulatory Reform

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In practice, there are very few countries at either extreme. Smart grid PPP projects are unlikely to be necessary in countries where comprehensive utility reform and regulatory reform has taken place. This is because market and regulatory incentives on existing market participants should be sufficient to ensure new smart grid technologies are adopted that can reduce costs or increase revenues. Further, reformed markets generally provide opportunities for new entrants that may utilize smart grid technologies to gain competitive advantage. Where regulatory systems create barriers to smart grid technologies (for example, by encouraging grid operators to be excessively risk averse), on-going regulatory reform is likely to be a better vehicle for encouraging the introduction of new technologies.

In Europe there are many examples where the regulatory framework is not a barrier to smart grid technology, and no explicit public sector funding is required. The Italian energy regulatory (AEEG) has a competition-based procedure that provides incentives for smart grid pilot projects for distribution through tariffs. Distribution-related smart grid network investments receive an additional 2 percent return on capital over 12 years where certain cost/benefit assessment criteria are met. In Romania, the regulator has indirectly promoted smart grid investments by strengthening penalties and rewards for network performance.

In Australia, national regulations were adjusted well in advance of smart meters becoming economic. The state of Victoria then opted for a government-mandated compulsory roll-out of smart meters (funded by increased meter charges), with state-specific technical requirements. However, other states left the power utilities to roll out this technology when it became economically viable from the perspective to the utility. Business-led roll outs in other states followed the Victorian roll out, with no material barriers presented by the regulatory regime.

However, Australia also presents an example of proactive barriers to the uptake of smart grid technology. The Australian Energy Market Commission imposed ringfencing regulations that essentially ensured that power distribution utilities were not able to use batteries to provide services to end users while also using them to reduce network peaks. Any use of batteries in the competitive market for providing power supply (rather than simply power distribution through a network) now must be ringfenced into a separate entity that is at arm’s length from the power distribution utility in order to protect competition from misuse of monopoly power.

At the same time, PPP contracts for smart grid technologies—just as other more conventional electricity sector PPP contracts—may not be viable in jurisdictions that have not introduced any reforms, or where the electricity sector is too dysfunctional to provide private parties with a clear entry point and assurance of payment.

Creditworthy or credit-enhanced vertically integrated utility

Smart grid PPPs would best be suited to market structures where there remains a high degree of vertical integration, but there is acceptance of outsourcing. There also needs to already be an established role for private sector service providers to the electricity system. Utilities that have an acceptance of outsourcing are more familiar with the procurement processes that accompany PPPs. A pre-existing degree of commercial understanding, and familiarity with processes will generate best outcomes and avoid risks. As outlined above, the advantages of private sector involvement include commercial incentives and competitive tension to achieve project outcomes. Risks that have a lack of sophistication or familiarity with private sector involvement can include the private sector taking advantage of knowledge gaps in negotiations.

Furthermore, the stability of the utility will be reflected in its creditworthiness. Private parties will make the creditworthiness of the utility (that is, the likelihood that they will get

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paid) a material condition of entering into a PPP. If creditworthiness is lacking, then some form of credit enhancement facility (for example, from a donor organization) will be necessary.

Prior experience with long-term IPP contracts

Independent power plant (IPP) projects in developing countries require similar pre-requisites as an energy PPP in a developing country. That is, the conditions for smart grid PPP viability are likely to be the same as the pre-conditions for IPPs. IPPs generally join a grid via an investment transaction regulated by an underlying contract, often a power purchase agreement (PPA). Regulators admit IPPs after approving the PPA to ensure these meet standards and regulations.

PPPs do not require an ideal regulatory environment to function, notwithstanding that smart grid PPPs are likely to be more successful where some degree of reform has taken place. PPPs need a robust contractual arrangement, just like a PPA for an IPP. In general, two broad conditions need to be met for PPPs to be feasible as a solution:

▪ The project is bankable. This means that financiers will lend against the project, and will require the following:

– Creditworthy counterparty (under regulations or donor credit enhancement measures)

– The project can attract not only equity finance, but also debt. This means the project will produce commercial returns and a stream of payments sufficient to cover principal and interest repayments in addition to a risk margin.

– Existing rules that allow private sector participation

▪ PPP contract as a solution is better than its alternatives. The list of alternatives is large and includes comprehensive regulatory reform.

The historical background in developing countries is important context to understanding which conditions are favorable to IPPs. In Africa, for example, IPPs have entered the market in response to growing need for investment in generation. IPPs have emerged as a frequently-used solution because sector reform has been slow. Despite ambitions to unbundle and privatize the electricity sector in Africa, the sector is still dominated by state-owned or controlled entities, often through the national utility company.

In other developing countries, attempts have been made over the past two decades to unbundle electricity utilities and introduce state-controlled competition and/or private sector competition. Often the state-owned utility was corporatized and made separate from the responsible ministry. Legislation accompanied this to mandate the restructuring and allow private and foreign participation. Provision was also often made for an independent regulator. Further reform steps include an independent regulator, unbundling, privatization and competition. Vertical unbundling of the incumbent utility was supposed to separate the competitive generation businesses from the natural monopoly transmission and distribution. Horizontal unbundling of generation was intended to achieve competition by facilitating trade in power via spot markets and bilateral contracts.

However, reform efforts generally stopped at the point of the utility corporatization and laws that allowed third party access to the grid, as well as new regulatory institutions. This resulted in many countries allowing IPP access to the market.

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Further conditions considered important to attract IPPs to developing countries include:7

▪ Independent regulator applying high-quality regulation.

▪ Planning, procurement and financial sustainability. This means that generation capacity expansion is planned by a credible party, even if this is the incumbent utility. The planning needs to be supported by timely procurement and well-defined investment opportunities for private and public sectors. Contracts (by definition long-term) require specialist negotiation expertise separate from the national utility and its generation or new build function.

▪ Finally, the creditworthiness of the off-taker is important.

Developing country context and challenges that affect viability for PPPs

In addition to the structural and commercial pre-conditions for PPPs, developing countries face particular challenges. These challenges are set out above in abstract terms in relation to regulatory reform status and utility ownership. However, challenges for the viability for PPPs in developing countries can be narrowed down in concrete terms:

▪ In-country public sector capability challenge. Often the capability for integrating new technology is not present. Even in developed countries, new technology requires time for all sector participants to get accustomed to new approaches, as the case studies illustrate.

▪ In-country lack of familiarity with private sector provision of services. Where the public sector has a prominent role in provision of infrastructure services, the involvement of commercially-minded providers can result in frictions as consumers and counterparties get accustomed to the change.

▪ Creditworthiness challenges unique in developing countries. Private sector parties will always require certainty that their revenue expectations will not be put at risk due to counterparty creditworthiness issues.

▪ Legal uncertainty for investors due to weak institutions. Developing countries can be politically unstable, which affects the investment climate, and certainty. Institutions can be weak, and produce unpredictable results affecting an investment’s value.

1.4 Key Barriers to the Successful Adoption of Smart Grid Technology

This section summarizes the key barriers to the successful adoption of smart grid technologies worldwide.

1.4.1 Financial viability

Smart grid technologies represent innovative—and hence risky—solutions to existing problems. In many power systems, sector participants are not financially viable due to a broad range of regulatory and policy failures (which have been canvassed elsewhere). Utilities that face financial challenges are unlikely to prioritize investment in novel technology that may create additional financial risk arising from any failures.

Various solutions have been put in place to enable PPP-style contracts to overcome financial viability barriers for more conventional technology investment by utilities.

7 Eberhard et al. (2016), Independent Power Projects in Sub-Saharan Africa: Lessons from Five Key Countries, World Bank Group:

“Elements that appear to be particularly important in supporting IPPs include least-cost power expansion planning, effective procurement and contracting processes, and ensuring the financial health of off-taker utilities.”

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Ideally, such solutions involve advanced reforms of the power sector that enable power companies to collect sufficient tariff revenues to cover all costs. However, even in settings where such reform objectives have not been achieved, long-term contracts have been enabled through various credit enhancement measures such as government guarantees, donor grant support for ring-fenced operations, cash flow waterfalls and so on. In essence, while some basic financial pre-conditions need to be in place, there is no need to wait for perfection.

Furthermore, new energy technologies are inherently risky as they have had limited testing and are subject to rapid technological improvements. This makes large capital investment riskier for financiers. It also means higher risks for owners and operators of the new technologies in terms of the levels of operating and maintenance costs, as well as the timing of replacement expenditure.

1.4.2 Regulatory barriers

One of the hallmarks of a well-crafted regulation is that it allows for the appropriate level of flexibility in the regulated organization. Well-designed regulation should accommodate dynamic change in technology and in consumption preferences.

However, most regulatory models around the world are a product of the history of electricity networks. The power sector has progressed through incremental improvements from the original technological and institutional basis. The sector is characterized by a degree of path dependence. On top of this, electricity market design puts a high premium on stability.

As a result, even “best practice” current regulatory models tend to be risk-averse and do not incentivize risky investments. Regulated investment returns tend to be set at levels consistent with a stable business environment. There is accordingly only limited dynamism in regulatory models in response to changes in technology or consumption preferences.

New technologies, by their very nature, are untested and uncertain. This makes them unattractive for adoption from the perspective of regulated utilities – if the risk pays off, there is limited benefit to them and if it does not, they may face penalties for failing to meet performance standards. While some regulatory models have emerged to address this (for example the Italian regulatory model) this is rare. Even in well-regulated markets contractual structures are being used to work around regulatory problems, for example in the state of Victoria in Australia, where the first roll out of smart meters was initiated in isolation from the standard regulatory regime. In this case, the state government and the private sector agreed a separate regulatory regime, technical requirements and funding model that were encompassed in a stand-alone regulatory contract to enable the roll-out to take place.

1.4.3 Regulatory barriers in developing countries

The challenge for developing countries goes beyond simple regulatory barriers to new technologies.

Developing countries often have legacy regulatory systems from monopoly utilities. Utilities with legacy regulatory regimes or monopoly structures that are common in developing countries are often risk averse. They face fewer incentives to take risks with smart grid technology. This is because the regulatory regime often has rigid technical requirements tied to conventional grid technology. Regulators can also be averse to new technology, where the impact on utility and network performance is uncertain. Finally, regulators and monopoly utilities can often lack the technical capability to manage new technology.

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Regulators can lack independence. This presents a barrier to enable new technology projects in the electricity sector to flourish. Regulators in some developing countries are close to or give more favorable treatment to an incumbent utility or government-owned monopoly. In such cases, potential investors will assess a higher investment risk due to insufficient certainty about regulatory treatment. This corresponds to a higher required return on investment, which is a barrier to investment that otherwise might have occurred.

Tariff barriers can also disproportionately occur in developing countries. Uneconomic tariffs may affect the commercial return available for a smart grid innovation and thus prevent market entry. Similarly, subsidy regimes can disproportionately occur in developing countries, and therefore also affect the commercial return available for a smart grid project.

1.4.4 Technical specifications and market rules

Due to the technical nature of the electricity business, all power systems have detailed technical requirements for service providers and market participants. These are often developed around the existing technologies and hence can hinder change. Negotiating and agreeing such technical changes can be a very time-consuming process.

Smart grid technology uptake in developed economies has been facilitated by interoperability standards. These standards in electrical grids ensure that multiple technology and communication systems can communicate with one another. Where such standards are not well developed, there may be barriers for the introduction of new smart grid technology.

Some systems simply have very detailed rules, that require specialist understanding, or are unique to the country. Cybersecurity concerns can also mean that utilities are reluctant to admit new technologies. Smart grid technologies have the main advantage of enhanced measurement and communication capabilities, which are used to gather and communicate detailed information about consumers. Where the consumers are households, smart grid data can reveal a lot about individual patterns of behavior—when people leave and return to the house, how many and what type of appliances are likely to be in the house. Smart grid technology can also allow for control of the customer’s appliances, as well as remote disconnection of the household. Given these new capabilities, there is now real risk of cybersecurity breaches that have a material impact on consumers. These factors can present an additional barrier to acceptance, and therefore uptake, of smart grid technology.

Conversely, other systems may not have well developed rules, and hence have to negotiate technical requirements on a case-by-case basis. This can also be a problem due to the increased transaction costs in negotiating and accommodating individual cases. In such instances, only investments that are large enough to justify the level of transaction costs will proceed. Therefore, only relatively few new investments occur in such systems. This system can justify the transaction costs of a few large projects to be procured but cannot justify the technical adjustments and accommodations (costs) of numerous project requests. However, in common law jurisdictions the absence of developed rules can be a blessing, allowing the uptake of new technology without the need for detailed regulatory changes.

Smart grids can be viewed as a collection of interventions to improve the functionality of the overall grid. This means that, by their very nature, the interventions tend to be smaller scale and variable in how they operate. They will often be tailored to very specific situations and conditions. This makes the adoption of smart grid technologies uniquely complicated from the point of view of technical standards.

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1.4.5 Technical barriers

Technical barriers can prevent smart grid uptake. These can be serious barriers in developing countries. Many smart grid technologies remain high cost, relative to conventional power system assets. As time goes, however, the cost premium for smart grid technology is falling. In many jurisdictions, there is a lack of capacity in operating and maintaining the technology in the incumbent energy utility. Given the novel nature of the technology, very few utilities have experience in operating and managing the technology. Finally, in many developing countries, a lack of reliable communications networks will hinder integration of new smart grid power assets in the short term.

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2 Detailed Assessment of Smart Grid PPP Model Design and Implementation

While there are no off-the-shelf PPP models for smart grids ready for replication, there are useful elements that can be drawn from the existing technology trials and procurements in order to develop a viable PPP model. To find the most useful case studies, the World Bank and Castalia jointly conducted a survey of smart grid projects worldwide, with a particular focus on examples that can be used to inform the creation of PPP models (Appendix A). From the survey, four categories of smart grid outputs (services) that can be supplied though PPPs were identified. Six case studies of these four categories are discussed. Three of the case studies are from developed countries. However, they have useful applications for developing countries. Models and PPP contracts can be developed by considering key aspects of the case studies and applying them in developing countries.

2.1 Selection of the Short List for Case Studies

The joint survey showed that, in general, smart grid business models are very much in early trial stages, with a limited pool of examples that are worth pursuing as potential candidates for case studies.

From the survey, an initial yes/no screen was conducted based on:

▪ Progress (completed/advanced/early)—The projects for closer study need to be in reasonably advanced state. They need to be well-developed and have clear features that allow them to be replicated at scale in different jurisdictions. Early technology trials and very small-scale demonstration projects that have not yet established scalability do not meet this requirement.

▪ Funding model (direct/mixed/indirect)—The case studies must include funding and financing elements that would allow the example if not be replicated then at least be translated into a stand-alone PPP contract with clearly specified outputs and performance targets, private financing and an identifiable revenue stream.

The survey focused on smart grid PPPs that can be introduced into a less than perfectly functioning market design or regulatory system. Overall, the study prioritized stand-alone and highly targeted projects that can work well regardless of the level of local institutional capacity, especially that of the local utility. Our focus was on smart grid technologies and PPP models that can readily be implemented in the near future. As other aspects of smart grid technologies emerge and become more established, many more opportunities for smart grid PPPs are likely to arise.

For example, there is considerable interest in installing charging facilities for EVs. In future, such charging networks will develop smart features which will contribute to the management of the power networks. However, the existing projects to install vehivle charging infrastrucure do not yet provide an immediate model for replication. In the longer term, EVs and EV charging infrastructure are likely to be a very important vector for adoption of smart grid technology as EV adoption rates grow and the demand profile of electricity systems changes as a result.

While there are many promising directions for the introduction of smart grids technology, the focus in this report is on those examples that provide immediate guidance for replicable PPP projects. This somewhat constrains the report to projects that address integration of renewables and decentralized improvement of poorly-configured and under-developed

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transmission and distribution networks—the types of solutions which can be readily implemented in the near future.

After the initial screen, the following factors for each case study were considered:

▪ Market design—Whether the market structure in the jurisdiction of the project is vertically integrated or structurally separated/unbundled. Is there retail contestability?

▪ Geographic region—A reasonable distribution between geographic regions was ensured.

▪ Specificity (high/medium/low)—Whether the project seeks to more generally promote progress towards smart grids, or whether it requires specific measurable outcomes, such as penetration targets for a particular technology, changes in customer behavior, or efficiency improvements. High specificity projects were prioritized, as these would be more readily implementable in a developing country setting and would be easier to translate into PPP structures.

▪ Depth (shallow/mid-level/deep)—The degree to which the PPP compels the provider to introduce and utilize smart grid technology. High depth projects would impose requirements for the roll-out and use of technology. Low depth projects involve the public sector promoting and incentivizing the take up of particular technologies, but not specifying the level of investment or the degree of use. Deep projects were prioritized, as such projects would be more readily implementable in a developing country setting.

▪ Regulatory framework (high/low independence of regulator, common law vs. civil law framework)—A variety of regulatory frameworks ensures applicability of the case studies over a wider range of countries.

▪ Information Availability (good/fair/poor)—The extent to which information is likely to be available. Projects with good and fair information availability were prioritized.

The working hypothesis for this report is that, in order for smart grid PPPs to be successful, especially in developing countries, the projects will need to be highly specific, deep and be able to be defined as stand-alone contracts. Projects that could be used to test that hypothesis were therefore prioritized.

On the basis of these considerations, the report examined the following case studies in-depth:

▪ Procurement by the National Grid Company of the Philippines of reactive power and other ancillary services from distributed battery storage. This report focuses specifically on the existing contract between NGC and AES Power (recently purchased by San Miguel Corporation) for the provision of 20MW of storage in South Luzon. While this specific contract is procured in the context of the need to stabilize the Filipino energy-only market, the procurement model, both in terms of performance specifications, funding structure and private financing was considered to represent a replicable example suited to different market models.

▪ Procurement of distributed battery storage to manage distribution system peaks and security of supply in Australia. Again, it is possible to replicate this model in different markets with different regulatory and market structures. A key advantage of this example is that the private operator is required to deliver

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outputs which are not dependent on the performance of the utility within which the contract is embedded. While Ausgrid is a well performing utility, the same results can be achieved within a poorly performing utility.

▪ USA turnkey automated demand response project. This is an interesting example of where a private operator is contracted to implement a comprehensive set of technical and contractual solutions that deliver customer demand response. This example can potentially be replicated in different market settings, with the performance of the private contractor not dependent on the quality of the utility and other participants in the market.

▪ South Korea Jeju Island Virtual Power Plant business model. The VPP model represents a very promising PPP structure that can be rolled out within different market settings and does not rely on the advanced infrastructure or the quality of performance of the incumbent utility. The Jeju Island business model represents a set of technical requirements, communication protocols and standardized commercial terms that could serve as a useful model of PPP contracts.

While projects involving the roll out of smart meters are informative and provide useful insights for PPP models, this report did not consider a specific PPP model for private financing and installation of smart meters. While such transactions can clearly easily be suited to implementation through PPPs, global experience with smart meter roll outs indicates that simple installation of such meters, without on-going incentive and obligation to ensure their acceptance and utilization, does not provide useful case studies for future replication.

The assessment of the short list is summarized in the table below.

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Table 2.1: Short List Assessment

Criteria Procurement of System Stability (Ancillary) Services from Battery Storage Providers

Energy Storage System Integration to Manage System Peaks and Increase Reliability

Procurement of Coordinated and Automated Demand Response by Large Commercial Customers

Virtual Power Plant Business Model

Geographic region Philippines Australia USA Korea

Country context Developing country, with many remote connections and high potential for small scale DG (solar) and storage

Developed country, with many remote connections and high potential for small scale DG (solar) and storage

Developed country. Addresses issues of coordination and implementation.

Developed country, world leader in smart grids. Full smart grid integration with RE, storage and demand response. Considerable effort put into development of replicable business models

Progress Completed Completed Completed Completed

Cyber security aspects Not relevant Compliance with strict security and privacy code

Compliance with strict security and privacy code

Compliance with strict security code

Funding and financing model

Funded from regulated transmission revenue.

Funded from regulated revenue and federal subsidies. Competitively

Funded from regulated revenue, federal subsidies and market arbitrage.

Privately financed merchant investment funded through regulated

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Competitively procured and privately financed

procured and privately financed

Competitively procured and privately financed

tariffs, time-of-use price arbitrage and government subsidies

Specificity High High High Medium

Depth8 Deep Deep Deep Deep

Market design Vertically unbundled, energy only market

Vertically unbundled, regulated distribution company with compulsory ring-fencing

Vertically integrated with IPPs

Substantially vertically integrated

Regulatory framework Common Law, independent regulator and system operator

Common Law, independent regulator

Common law, independent regulator and system operator

Civil law

Information availability Good Good Good Good

8 Depth refers to the degree to which the PPP compels the provider to introduce and utilize smart-grid technology. High depth projects would impose requirements for the roll-out and use of technology.

Low depth projects involve the public sector promoting and incentivizing the take up of particular technologies, but not specifying the level of investment or the degree of use.

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2.2 What Specific Outputs (Services) Should Smart Grid PPPs Deliver?

There are multiple ways of solving network challenges using smart grid technology. Not all are suitable for stand-alone PPP contracts. Some aspects of smart grid technology go to the core of utility operations (such as the “self-healing grid”) and are not suitable for outsourcing. Some technologies, such as integrating electric vehicles (EVs), are early in their development phase despite rapid growth in numbers and the building of charging infrastructure. This makes it impossible to definitively comment on the effectiveness of their PPP contracts.

It is often hard to capture the value of smart grids under typical power grid models. This is because smart grid benefits do not accrue to the party who would implement the particular smart grid technology. For example, automated demand reduction may be valuable to a grid operator, as it defers investment costs, but not to the power retailer that controls access to the consumer’s grid connection (meter) where demand (and therefore revenue) could be limited. Identifying where value and risk respectively arise is critical for assessing whether outputs can be delivered under a PPP model.

The six selected case studies demonstrate the currently-viable smart grid services that are best-suited for delivery through a PPP. They are: system stability from battery storage, coordinated automated demand response, virtual power plant and energy storage systems to manage system peaks.

These four potential models for PPP contracts do not represent an exhaustive list of services or solutions that can be provided by smart grids technology. For example, many developing country utilities are already investing in smart meter roll-outs. Smart meters provide advanced and detailed levels of information to network operators. This enables faster diagnosis of system faults and issues which enables more targeted maintenance and the ability to anticipate problems. In addition, with better detection, remote billing enables significant reductions in non-technical losses. However, while significant advances are already being made with smart meter roll-outs, there is less opportunity to scale up the use of such technology and to maximize benefits from the use of PPP contracts compared to the four key areas that have been identified.

2.2.1 System stability services from battery storage providers

System stability services, often called ancillary services, can now be provided by battery storage deployed in electricity grids. Ancillary services are services that support the transmission of electricity from generator to end-user. They include load regulation, spinning reserve, non-spinning reserve, replacement reserve and voltage support.

Traditionally, system stability services were procured from a variety of generators running at less than full capacity, where the grid operator could request short-term variance in generation (either rapidly increasing or decreasing generation). Different mixes of generation type affect the ease with which a grid system can integrate ancillary services. In systems with a high proportion of hydro generation, ancillary services are relatively easily controlled by varying the load and frequency of hydro generation. In such grid systems (for example, New Zealand), ancillary services do not need to be provided by specialists. Gas generation can also rapidly scale up or down load to meet the need for ancillary services. However, where thermal coal generation is prevalent, and especially where only a small number of plants provide grid load, system stability services can be more difficult to procure due to the slow responsiveness inherent in those plants.

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The cost of system stability services is normally priced at the marginal fuel cost for the plant providing it. Therefore, new ancillary services provision is likely to be economic where their price can be lower than marginal fuel cost of existing generation capacity, or where growth in demand is running ahead of the capacity to build new generation plants.

As demand around the world for power increases and more variable renewable energy (such as wind or solar) and distributed generation plants are commissioned, the requirements of the system to ensure stability, reliability and security likewise increases. Ensuring the integrity of the system is essential to promote system reliability and stability and therefore encourage investments and growth.

2.2.2 Coordinated and automated demand response by mid-size commercial customers

Smart meter roll outs for residential consumers are happening in many countries, but further regulatory and market reforms will be needed to enable efficient pricing signals to be sent to consumers. These are not addressed here, as the regulatory and institutional reform required for this will likely take a long time to achieve in developing countries, and indeed in many developed countries.

Due to the relatively small number of large industrials, grids often already have bilateral agreements in place enabling demand response.

Small and Medium Enterprises (SMEs) have historically posed problems for the grid—they are too diverse to effectively target and too many to deal with on an individual basis. A form of PPP contract has been identified that effectively creates a “middle man” between the grid and a group of SMEs.

The grid will deal with the counterparty to the PPP contract in the same way that they would deal with a large industrial. The counterparty, on the other hand, is responsible for ensuring that the SMEs collectively produce the load reductions on the relevant part of the grid that to the contract provides for. This allows the grid to transfer this electricity demand risk to a third party. While the third party is effectively taking technical risk (ensuring the technology to shed load works as intended) and commercial risk (ensuring it always has sufficient individual agreements for sheddable load at a cost that is below the price paid by the grid).

2.2.3 Virtual power plant business model

VPPs are another effective way of integrating variable renewable energy into the grid. In the VPP model, an energy aggregator gathers a portfolio of VRE generators, energy storage and demand response and operates them as a unified and flexible resource to supply reliable energy to the utility.

While individual components of the VPP may be highly variable and difficult for the grid operator to absorb, the VPP manages variability within its portfolio and presents to the grid the required firm output. VPPs use software and advanced communications to dispatch and coordinate a portfolio of storage sites, variable renewable generators, and customer-site demand response control units.

2.2.4 Energy storage system integration to manage system peaks and increase reliability

Energy storage systems (ESSs, in other words batteries) can manage system peaks and increase reliability. The total amount of grid investment necessary generally depends on peak demand—higher system peaks require larger generation capacity and higher rated lines. Reducing system peaks, therefore, is an effective way of reducing overall costs.

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There are broadly two approaches to shaving system peaks: through consumer demand response and through energy storage. Energy storage does not affect demand peaks but flattens the load from the perspective of transmission and distribution grids, and electricity generators. ESSs can charge up during off-peak periods to discharge in peak periods.

2.3 Lessons Learned from the Case Studies

Three of the six case studies chosen are from developed countries (Australia, South Korea, United States). The remaining case studies are from India, Mexico and Philippines.

There were no examples of models that could simply be adopted without material changes—smart grids are a new technology, which is still in many cases at the stage of research and development or small-scale trials. Use of smart grid technologies in developing countries is in its infancy, and so limited potential case-studies exist. Further, of the very few examples where smart grid technologies are being deployed in developing countries, this is not in the form of PPPs with meaningful ongoing private sector participation.

Some countries are moving in a positive direction toward greater inclusion of smart grid technologies with private sector participation. For example in India and Mexico, government-owned utilities have paid private sector entities to install specific smart grid technology components for the utility to own and operate. There was no ongoing performance-based participation in owning or operating the smart-grid assets, however, this could occur in future.

As a result, the analysis focused on examining mainly developed-world case studies—because those case studies had crucial characteristics and features which would lend themselves well to creating archetype PPP models that could be applied in a developing country context of incomplete regulatory reforms or poorly regulated electricity sectors.

Utilities’ capacity may hinder the development of smart-grids in developing countries for both, PPPs and public procurements A barrier to having smart grid services in developing countries is that utilities often do not have the institutional knowledge or technical capacity to manage the system risk from smart grid services. Not only can utilities not implement the services, they also don’t have the capacity to procure the services from the private sector. Nor do they have the genuine desire or incentives to try something new and therefore to develop that capacity.

In many utilities, there is strong preference for conventional low-risk engineering solutions. For example, a recent detailed review of the attempts by PLN, the Indonesian power utility, to implement mini-grids had identified internal institutional resistance to mini-grid solutions. The review found that PLN did not have a process for determining whether a mini-grid or extending the main distribution network was the least cost way to increase electrification. A lack of evaluation criteria meant that PLN had a preference for extending the distribution network. Developing mini-grid solutions in areas away from the grid would in many cases have accelerated electricity access.

Utilities in developing countries may be more comfortable and better placed to manage the risks if the contract for smart grid services were structured like a contract for a PPA. This is because PPAs are used frequently and successfully in developing countries between utilities and IPPs. The PPA model effectively de-risks the systemic risk component of new energy capacity procurement.

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Services can be bundled in a way that utilities are comfortable with

Models with pre-packaged contracts can be developed rom considering the key contractual terms, incentives (penalty and reward regime) and technical specifications of the case studies.

The contracts, structured like a PPA (and largely identical to a PPA from the perspective of the utility), would mean that the private partner would deliver a specific bundle of smart grid services for a pre-determined price, decreasing the system risk for the utility. Risk decreases for the utilities as they have agreed to a specific service that they know they can integrate into the system.

At the same time, the private partner is able to focus on technical, financing and commercial risks, which they are well-placed to manage, while not taking on the system risk, which remains with the utility.

2.4 PPP Structure Considerations

There are three main factors to consider when designing any PPP contract: risk allocation, stakeholders, and financial returns.

Risk allocation: It is necessary to ensure that it is acceptable to both parties. The structure of the contract determines which party holds a specific type of risk. The allocation of technology risk is particularly important in this case. Since these technologies are largely untested, the quantum of risk is quite high. The case studies illustrate that even in developed economies, the public sector tends to take most of the technology risk. This analysis explores if this is ideal for developing countries as well.

Stakeholders: It is important to create a structure that works. All parties who are critical to the success of the PPP must be involved. The PPP needs to bring three distinct groups together:

▪ Technology companies: Smart grid technologies are at the cutting edge of technology. It is therefore imperative to include experts. All of the case studies involved technology companies closely in the project and they were imperative for success.

▪ Sector participants: Technology companies may be subject matter experts, but it is highly likely that they have no operational experience in the electricity sector. In order to integrate smart grid technology into utilities’ systems, it will be important to bring sector participants into the contract. This is a particular focus for developing countries where operational expertise will be highly specific to the particular mix of generation, transmission and distribution. This could include generator IPP experts, aggregator companies or local power sector participants.

▪ Financial investors: All PPPs need investors. The value of PPPs can be significantly improved by harnessing the incentives of financial investors. Investors and lenders generally undertake their own project analysis based on experience (often market-leading knowledge of sectors) and a profit-driven incentive to ensure the benefits of a project exceed costs. Involving investors can mean that non-viable projects are filtered out, as financial investors are less prone to suffer optimism bias than public sector or in-sector parties.9

9 Engel, E.,Fischer, R.and Galetovic, A., (2014), The Economics of Public-Private Partnerships: A Basic Guide;

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Financial returns: the financial considerations of each PPP structure are symbiotically linked with the risks borne by each party. Private sector participants will require a commensurate return for all risks that these parties bear.

The optimal solution is to induce the private party bear the risks that it can mitigate and shield it from the risks that are out of its control. Requiring the private party to accept the right risks incentivizes it to perform. Allowing it to avoid risks that are outside of its control allows for a cheaper deal.

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3 Categorization of Relevant Smart Grid PPP Models

In this section the case studies and preceding analysis are drawn upon to drill down towards the identifying models for the implementation of smart grid PPPs.

3.1 Ancillary (System Stability) Services from Battery Storage Providers: Masinloc, Philippines AES/NGCP Project

The following case study is from Philippines, where a private sector IPP developed a battery energy storage system (BES) adjacent to a conventional power plant and sells ancillary services to the national grid operator.

The Masinloc BES represents a model that can be replicated as a PPP which utilizes smart grid technology. The BES provides a stream of system stability services that are of economic value to the utility. If extremely short-term load is required, the utility can call on the BES to provide load. Risk for the provision of load is incurred by the BES. Such services can be separately defined in a contract, with risk allocated to the private provider and payment obligations from the utility.

Background

The Masinloc power plant complex in Zambales Province on Luzon Island, Philippines owned by the private San Miguel Corporation contains a battery energy storage system (BES) with 10MW installed capacity and flexible resource of 20MW. The BES had a total project cost of US$13 million. It is connected to four coal-fired units with 315-335MW capacity each. At the time of its building, it was one of the first advanced energy storage installations in South East Asia, and among the largest in Asia.

San Miguel acquired the complex in early 2018 from the United States company AES, who acquired the 1998-era facility when it was privatized by the government in 2008. AES developed the BES with own equity finance in 2016.

The Masinloc BES is an example of a resource connected to base load generation systems that can be deployed to the grid in situations where reactive power and voltage regulation is needed. Energy storage solutions such as this can perform such ancillary services to the grid much more effectively than traditional grid resources. A further feature of the BES is the flexibility to rapidly deploy load (up to 10MW) or absorb load.

The BES and the National Grid Corporation of the Philippines (NGCP) entered into an agreement for the provision of the reactive power and voltage regulation services. While the specific contract between NGCP and Masinloc BES procures regulating reserve, the procurement model provides a good replicable example suited to different market models in the developing world.

The Philippines government Energy Regulatory Commission (ERC) promulgates and enforces the grid code, which sets the requirements for ancillary services (and a range of other specifications) that the grid operator must comply with. NGCP is a private company with the concession to operate, maintain and develop the national grid, while ownership of the transmission assets is retained by the state. NGCP therefore is required and incentivized by the ERC to procure ancillary services for the grid on long-term contracts.

NGCP has entered into a number of contracts with battery storage providers such as Masinloc BES to supply reactive power and voltage regulation in response to greater market penetration by variable renewables. It does this through a competitive procurement process, inviting all IPPs to participate in the provision of ancillary services. However, it

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may also directly agree contracts with a third party. Once a viable partner is identified, NGCP carries out various tests to ensure the provider meets the technical requirements.

The contracts it enters into must be approved by the ERC . The cost of ancillary services is socialized across all network users through regulated transmission charges. Figure 3.1 below illustrates the legal and commercial structure.

Figure 3.1: Masinloc BES

Key contractual terms

The ancillary services (regulating reserve) are provided to the NGCP under a standard form “Ancillary Services Procurement Plan” (ASP).10 The ERC must approve the contract prior to it coming into effect. The contract is agreed to subject to the Open Access Transmission Service Rules (OATS Rules).11

The ERC reviews the terms to ensure ASP will benefit consumers with reference to the quality, reliability, security and affordability of the proposed arrangement. There is a particular focus on the rates agreed to between NGCP and the BES, as these are ultimately passed through to consumers. The ERC’s decisions are public and published on the ERC’s website.12 The ASP is valid for a 5-year period, renewable for another 5-year term.

Masinloc BES is paid a two-part fee. The largest component is a capacity payment, which is for the regulating reserve capacity Masinloc BES must consistently bid into the grid. This is paid at PhP 2.20/kW/hour (US$ 0.042/kW/hour13). A much smaller fee is paid for actual dispatched energy of PhP 0.05/kW/hour. The dispatched energy fee reflects the very small cost to Masinloc BES of electricity losses between charging up the battery and discharging to meet a call. The larger capacity fee reflects the value that Masinloc BES is providing the grid, that is the capacity to meet demands on it for regulating reserve.

A number of methods exist to determine the rate that a provider and NGCP can agree, in order to receive ERC approval, including new build methodology, opportunity cost methodology and comparative revenue methodology. These are used to find the

10 Ancillary Services Plan: Rules, Terms and Conditions for the provision of Open Access Transmission Service, standard

form contract provided by ERC and available at: https://ngcp.ph/download-file.asp?ContentID=316

11 Open Access Transmission Service Rules for the Philippines, available at: www.erc.gov.ph/Files/Render/media/OATS_Rules_Dec2006.pdf

12 Masinloc BES submitted its application for approval of the ASP to ERC on 28 February 2018. The application was moved to the next stage of approval, with a public hearing schedule in May 2018. Final approval is expected in mid 2018.

13 PHP/USD = 0.0191736, from www.xe.com accessed on 23 April 2018.

http://www.erc.gov.ph/Files/Render/media/OATS_Rules_Dec2006.pdf

http://www.xe.com/

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hypothetical cost for providing the ancillary services, in addition to which the provider may charge a specified margin.

Technical specifications

Under the ASP, the BES supplies regulating reserve, which is the generating capacity necessary to adjust total system generation over short periods of time to match random fluctuations in total transmission system load. NGCP is required to allocate a percentage of the system demand for each hour as the regulating reserve and provide this to the BES. This enables the ancillary service provider (Masinloc BES) to respond as needed.

By purchasing regulating reserve, the grid operator (NGCP) can control the power system

frequency to within specified limits. The contractually specified frequency limit is +/‐ 0.6 Hz of the standard 60.0 Hz in order to ensure quality of supply and security of the grid.

In practice, this means the BES bids in load to the grid intended to maintain grid frequency levels (that is, it discharges the battery), but it can also accept load to perform the regulating function (that is, it absorbs excess frequency in the grid by charging up the battery). The Masinloc BES has installed capacity of 10MW with flexible resource to charge up to 20MW. It shares facilities with the coal-powered units in the Masinloc complex, meaning that power supplied to the grid is seamless with the traditional coal plants.

Penalty and reward regime

The financial incentive on Masinloc BES is the capacity payment it receives for having regulating reserve on standby. NGCP faces financial incentives from the DoE to obtain ancillary services to ensure stability of the grid. Financial penalties are imposed on Masinloc if it fails to provide standing capacity and then meet its load obligations when called upon. The financial penalties on NGCP are reflected in its 25-year concession agreement with the government to operate the national grid.

Technical compliance with the performance specifications in the ASP, the OATS Rules and the Philippine Wholesale Electricity Spot Market (WESM) rules is judged as a matter of fact by regulatory monitoring and self-reporting. Failure by Maslinloc BES to meet the specified regulating reserve capacity on demand results in a series of graduating penalties.

Firstly, any failure to provide capacity results in non-payment of the PhP 2.20/kW/hour contractual amount. Secondly, the WESM rules specify a graduated series of financial penalties for ancillary services providers. The severity of penalty depends on the level of non-compliance and the level of impact the breach causes in the market and/or on the WESM participants.14 Matters that the WESM takes into account that aggravate the level of financial penalty include the provider’s history of breaches, any failure to take due diligence, the extent that a provider benefited from its own breach, and the financial and general impact on the market. Financial penalties can be up to a maximum of PhP 50 million (US$ 958,68015). Mitigating factors include unusual circumstances, unintentional nature, voluntary disclosure and mitigating steps taken.

The contract took longer than usual to negotiate due to NGCP’s unfamiliarity with the use of rapid battery discharge to provide ancillary services. Historically, ancillary services have been provided by generators in the Philippines. However, all reports suggest that the model is working well and a similar battery project is underway in Cebu.

14 WESM Financial Penalty Manual,

http://www.wesm.ph/download.php?download=RExEQldFU00tTVNDLTAwMS5wZGY=

15 PHP/USD = 0.0191736, from www.xe.com accessed on 23 April 2018.

http://www.wesm.ph/download.php?download=RExEQldFU00tTVNDLTAwMS5wZGY

http://www.xe.com/

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3.2 Coordinated and Automated Demand Response by Large Commercial Customers – California Honeywell Projects

The following case study examines an automated demand response (ADR) project built and serviced by Honeywell for three Californian utilities.

While the ADR project is not structured as a PPP, it provides basis for replication as a PPP. The technology provider (Honeywell) has enabled private aggregator companies to provide firm negative load to the three Californian utility companies. Honeywell’s technology improves the measurement and prediction of demand. This enables large consumers, and the aggregator companies who can bundle up these consumers, to automatically respond to utility requests to drop load. The risk of providing sufficient responsive negative load can be clearly defined. This risk can be transferred to private aggregators, and it is possible for these to receive remuneration from the utilities for this service.

Background

Honeywell’s ADR technology was provided to medium sized end-users to reduce electricity consumption at peak times. It involved an ADR platform developed by Honeywell that communicates with medium-sized business end-users’ advanced energy management systems (EMSs) to implement electrical equipment curtailments. End-users were able to choose equipment that could be turned off without significant losses, such as non-essential lighting, elevator banks, pumps, motors, compressors and refrigeration systems.

The project was partly funded by a Department of Energy (DoE) grant and by the realized value from the consumption reduction. The project also involved utilities, aggregator companies and end-users in addition to Honeywell and DoE.


The key stakeholders in the project were DoE as the funder of the SGIG subsidy program, Honeywell as the provider of the technology solution, three Californian utilities, aggregators and the end-users. A summary of the contractual arrangements between stakeholders in shown in Figure 3.2.

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Figure 3.2: Contractual Arrangements Between Key Stakeholders

While there was economic value in these arrangements for aggregators, utilities, end-users and Honeywell, the DoE grant was material. This was provided under the Smart Grid Investment Grant (SGIG) program in 2009, part of a US$3.4 billion fiscal stimulus to accelerate the modernization of the nation’s electricity market and achieve a smarter electricity grid.

The SGIG program covered up to 50 percent of investments by electric utilities and other entities for projects that promote the goal of smart grid deployment, including development of component technologies. In this case, a US$11.9 million grant contributed to a total project value of US$22.7 million. The DoE procured the project via a competitive tender, where applications where judged on the net benefits to consumers, companies, and society as a whole. The SGIG program required certain milestones to be reported and progress reporting in order for grant recipients to receive payment.

The grant was for a project to deliver automated demand response solutions for Californian utilities and their commercial and industrial customers. Honeywell’s role included:

▪ Developing the ADR system

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▪ Working with local utilities and aggregators to recruit commercial and industrial customers to participate

▪ Conducting audits to advise customers on load control strategies

▪ With the utilities, Honeywell provided the ADR system at low or no cost for most customers.

Honeywell partnered with three Californian utilities. The utilities paid US$200 to $300 per kW of curtailable load to customers for the ADR systems. In return, the utilities benefited from the project through reduced peak demand, which helped delay or avoid network investment. The utilities Honeywell partnered with for the project are:

▪ Pacific Gas and Electric Company (PG&E)

▪ San Diego Gas and Electric Company (SDG&E)

▪ Southern California Edison (SCE)

Some customers signed up directly with the utilities. To sign up directly with SCE, customers had to be a non-residential customer, within SCE’s service territory and have an interval data meter to monitor energy use. Customers had to sign up to a minimum 12 month period (but could sign up for more) and they received bill protection for the first 12 months of the contract. Bill protection meant customers would not have to pay more than they would without the ADR system.

Other customers signed up through aggregators. Aggregators put together groups of customers willing to participate in the project. Aggregators then sold a package of curtailable load to the utilities. The aggregators were held responsible by the utilities for providing the load specified in their contract. If requirements were not met, aggregators were penalized.

Multiple aggregators were involved in the scheme, including Enernoc and CPOWER. Enernoc sold curtailable load to Southern California Edison’s (SCE). Enernoc’s ADR program has similar eligibility criteria as signing up directly with SCE, except with a minimum sign up time of 36 months.

61 customers were involved in the project, at 282 sites, and with a collected total of 49MW of curtailable load. Ideal customers were large water pumping stations, big box retailers, and large manufacturing plants. Honeywell installed and customized the energy management system (EMS) capabilities that customers needed to automate curtailment of specific equipment.


Due to the grant payment structure, DoE only bore the risk of accountability for the public benefits of the program. This was assured by Honeywell’s grant payments being conditional upon meeting agreed milestones. The DoE structured the program in a way to obtain a range of wider benefits to customers and grid stability at peak times (as well as fiscal stimulus objectives).

Honeywell was in turn incentivized to execute the project successfully. Honeywell took on risk to be an industry leader with ADR technology. The US$11.9 million DoE grant covered a significant portion on Honeywell’s investment, but not its total costs.

According to Honeywell executives,16 the grant was material to the viability of the project. The three utilities helped recruit customers and paid US$200 to $300 per kW of curtailable

16 Interviews with senior Honeywell executives involved in the ADR project in April 2018.

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load to install the ADR system. The utilities then benefited from having curtailable load. The curtailable load helped shave the demand peaks, which helped delay or avoid investment for the utilities. From the utilities’ perspective, the costs of curtailable load outweighed the benefits. The amount the utilities were willing to pay is likely a good indication of the value the utilities place on the benefits received (US$200 to $300). The average ADR cost was approximately US$400 per kW of capacity. The grant helped make up this shortfall and to make the project viable.

Customers had no investment costs and received financial benefits such as incentive payments, lower rates during off-peak periods, and lower bills. These benefits were from curtailing load at peak times, optimizing energy consumption. The ADR technology was installed with only minor disruptions during the energy audit and installation. The low cost was critical, as had the project involved large up-front investment with returns unknown, participation would have been low. The DoE grant covered Honeywell’s installation costs of the ADR technology, encouraging customers to participate.

Customers received financial benefits without taking on any risk. Customers that signed up directly with SCE received bill protection for the first year. Bill protection ensured that they wouldn’t have to pay more than they would with the ADR, eliminating any risk. There are also no penalties for customers with SCE. However, conditions can apply for different programs. For example:

▪ For the capacity bidding program, if the actual reduction was less than 75 percent of a customer’s nominated reduction on an hourly basis, capacity incentives were reduced

▪ For the summer discount plan, energy rates are significantly higher during critical peak pricing events.

The involvement of aggregators also decreased the project risk for the utilities. Aggregators grouped together customers and guaranteed a certain amount of curtailable load to the utilities. They were then rewarded by the utilities per kW of curtailable load they could provide. However, aggregators ran the risk of penalties if they did not meet the requirements in their contracts with the utilities. The penalties led to aggregators securing 1.5-2 times the amount of curtailable load obligated to utilities.


Honeywell provided constant technology services throughout the project, in addition to the installation. Honeywell customized the ADR system for individual customers and controlled the central server. The ADR system allows consumption of electricity to be decreased in response to synchrophasor signals from the utilities. This signal is either related to system/network issues to preserve grid reliability or it is in response to price changes. The ADR system thereby improved the efficiency in grid and generation investment as well as operational efficiency.

For customers to participate, they had to have more than 200kW of connected load. The minimum amount of connected load is to ensure the benefits outweigh the costs. Customers also had to have a qualifying interval data meter to monitor their energy use.

Peak pricing mechanisms increase customer incentives. Customers were shifting their demand from one time of the day to another, and only in some cases decreasing demand. Without peak pricing, the utility would still benefit but customers would not, as their electricity bill would be the same. Therefore, peak pricing tariffs incentivize customer participation by making shifting load attractive.

The project resulted in direct benefits for customers and the utilities:

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▪ In 2009, there were 49MW of curtailable electricity demand. That number has now increased to 110MW of reliable demand response capacity

▪ Coastal Pacific Foods Distributors reduced its monthly bill from US$50,000 to US$35,000 and reduced total consumption by 25 percent. Also, Honeywell’s own manufacturing facility in Torrance received more than US$75,000 in credit over 11 demand responses.

3.3 Virtual Power Plant Business Model

VPPs are systems, managed by software and computer networks, that aggregate the capacity of multiple distributed energy resources (DERs) at a particular transmission node to enhance power generation or sell power on the open market. VPPs have taken a typical form of coordinating sources of power through a technological system and then feeding this as a single source into the grid, akin to a conventional power plant.

Jeju Island, Korea served as a test-bed for VPP applications, along with numerous other smart grid technology applications. The test-bed was not commercial but supported by a government program intended to trial and test as well as catalyze VPP models.

Background

As with all smart grid technologies, VPPs are growing in importance as variable renewable sources of energy also grow in significance. The most common form of VPP is a single operator of the centralized control system, which is responsible for combining various sources of power and dispatching these as grid demand dictates. The DERs that act as the “generation” capacity for the VPP are often renewable solar, wind, hydro and biomass sources or large consumers who are capable of being flexible with their demand. VPPs can also include aggregation of emergency generation or ancillary generators at large commercial or industrial premises. The conventional VPP operator must source the DERs either directly or through aggregator firms.

In addition to the technology systems, VPPs are based on a business model of contractual relationships with DERs or aggregators and the grid participants. VPPs create value by harnessing latent or variable power supply (or demand reductions) and smoothly integrating this into the power system. They do this by collecting rich data on capacity from the DERs and combining it with sophisticated communication systems to tell the DER when to ramp up or ramp down production (or reduce consumption in some cases). VPPs can also facilitate trading of electricity due to their ability to rapidly communicate with DERs and grid operators. The VPP must balance its obligations to the dispersed sources of power (the DERs) and obligations to the grid system operator.

The existing VPP model offers firm power on a similar basis to an IPP (or a conventional power plant in a spot market, where such a market exists) into the grid. The VPP operator has to manage its portfolio to deliver the required level of firmness. This is typically achieved through bilateral contracts between the VPP and its DERs.

In order to achieve the required level of firmness, the VPP has to maintain sufficient level of DER to ensure that it is always able to meet its contractual requirements. In practice, this means “over-contracting” with DERs. That is, the ratio of contracted DER capacity to the capacity provided to the grid is always materially greater than one. The ratio can start out quite high for a new VPP and reduce over time, as the VPP learns how to use the various DER and demand response resources more efficiently.


The Jeju Island smart grid test bed was a government supported venture involving agencies and 168 Korean and foreign firms. It operated from December 2009 until May 2013. Public

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funding, support, and coordination was critical for the project. As an exploratory research and development initiative, contract outcomes were focused on trials of the technology, rather than cost recovery. The technology and energy sector firms involved also partially financed various Jeju trials. The VPPs trialed in Jeju were a mix of battery storage, VPPs using EVs, wind DER and ADR.

During research and interviews with Korean VPP company representatives, the staff at Korea Institute of Energy Technology Evaluation and Planning (KETEP) and Asia Development Bank experts, more detailed information became available. The VPP technology trials on Jeju themselves were not particularly successful, catalyzed further development of the VPP sector in Korea.

The VPP business model has developed further in Korea since the Jeju trial. Legislative and policy changes have contributed over the past three years. One significant development has been aggregation of small-scale generation, storage and demand response into larger-scale firm capacity that is bid into the Korea Power Exchange. Multiple sources of around 100kW or less are aggregated, or brokered, by VPPs and bid in. At the end of May 2018, licensing requirements were relaxed for small-scale generation and capacity provision, enabling further dynamism in the VPP sector because additional capacity sources can be added.

Figure 3.3 illustrates the arrangement in Jeju Island for the VPP trial and the government support across the entire project. This model can be reflected

Figure 3.3: Jeju Island VPP Test Bed

Supplementary research on Korea has confirmed that various energy and technology companies have acted as the VPPs—contracting with the utility and with various energy sources (batteries, wind DER and ADR), while other technology companies acted as the

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technology provider to the VPP—limiting their scope to providing the hardware and software that enabled the VPP to operate from a technical perspective.

In those cases, the VPP paid not only for the energy services provided to it, but also for the technology services provided by the technology provider. An alternative model is for the VPP to have and to operate its own technological solution.

The key risk that VPPs assume in a power grid is the risk to deliver a fixed amount of load to the utility. VPPs are better placed than individual vRE generators, consumers with ADR, or owners of auxiliary generators (for example large industrial plants with internal generation capacity). This is because VPPs have generally developed their own sophisticated smart technology solutions (either hardware, algorithms or a combination of both) that enable them to pool a set of electricity resources in a ‘virtual’ plant. VPPs assume the risk of managing the difference between their commitment of load to the utility with their ability to pool sufficient load together from DERs, vRE, ADR and other sources.

A new evolution of the VPP is a distributed energy exchange model. This model moves beyond bilateral contracting of the conventional VPP by facilitating an internal marketplace for the services the DER can offer. One version of such market-place is being developed by deX, an Australian company with seed investment from two Australian State governments, the Australian Renewable Energy Agency, utilities and technology companies.17

Key pillars of the deX VPP business model

deX stands for distributed energy exchange and is a marketplace for energy services that individual DERs in the network can provide. It can supplant the aggregator role of VPP by allowing potential power supply to clear directly with demand. It does this through a detailed understanding of the total capacity of a grid, achieved through Advanced Distribution Management Systems (ADMS) or very detailed understanding of the network map. This information allows the deX marketplace to know with certainty the capacity of participants and make this information visible to others. Price signals can then be transmitted via deX between DERs and grid operators and local networks. These price signals enable both the power supply side (DERs) and the power demand side to achieve bi-directional energy interactions. deX enables ‘behind the meter’ DERs such as domestic solar panels to participate in the market.

Services to DER, network participants and network operators

deX can offer three services:

▪ Trading between participants, including directly with customers

▪ Network services so that DER can trade services with networks companies to provide non-network solutions to defer or avoid network investment

▪ More sophisticated real-time balancing within the VPP than is possible through bilateral contracts, enabling system operators to procure demand response capacity and emergency capacity.

The deX model will require further regulatory accommodation.

What are the key contractual terms?

The VPP contracts with the off taker/retailer (utility) offering capacity with a specified level of availability within a distribution or transmission network node (if there are

17 More information on the deX model is available in deX White Paper (2018), Greensync, Melbourne, available at:

https://greensync.com/solutions/dex/

https://greensync.com/solutions/dex/

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distribution or transmission constraints between nodes, energy fed by VPP components in different nodes cannot be balanced). These contracts can be similar to IPP contracts, or sourced competitively by the utility. In developed countries or deregulated wholesale markets, VPPs operate in the same way as any other private generator by bidding in load to spot markets or participating in auctions (for example, the Korean KPX market or UK capacity market). The terms of the contract with the utility are often subject to regulatory settings in developed countries, particularly where certain levels of VRE is specified.

The VPP contracts with DERs and other generators and consumers capable of ADR to secure sufficient load for its commitments to the utility. The VPP must construct a portfolio of resources which can deliver the contracted level of security at the relevant nodal location. This means that the VPP carries substantial risk in managing the difference between its obligations to the utility and its supply of load from the contracted resources.


VPPs are subject to availability requirements pursuant to their contract with the utility or the regulatory requirements imposed. In addition, the VPP receives remuneration for the actual energy load supplied. In this sense, VPPs are similar to conventional IPPs and generators in competitive markets. The VPP will in turn provide compensation to the contracted resources that constitute its portfolio.


Technical specifications for VPPs depend on the regulatory framework and generation mix. In Korea, the KPX system enables VPPs to broker across a range of diverse, and small-scale power sources including ADR, VRE, hybrid ADR/vRE and auxiliary generation (for example emergency generators). Various policies in Korea favor greater use of renewables. In the United Kingdom, for example, GHG emissions-reduction policies favour aggregation via VPP of ADR rather than more carbon intensive sources such as auxiliary generators.

In all cases, VPPs must ensure that the variability of generation sources can be managed so that the commitments to the power market (in de-regulated systems) or the utility are met. Most VPPs have sophisticated software and algorithms to ensure this. Predictive models are developing as experience in aggregating and broking between the diverse sources of power and the grid (or utility) develops. In a functional sense this is similar to the technical requirements imposed on IPPs in many countries; IPPs must carry the technical risk of meeting generation demands imposed under the power purchase agreements.

3.4 Distributed Energy Storage System Integration to Manage System Peaks and Increase Reliability - Upper Hunter Region, Australia

In 2010, the Australian Government chose Ausgrid (a recently privatized utility in New South Wales) to lead a AU$100 million initiative called Smart Grid, Smart City. The initiative lasted 3 years and covered 30,000 households across Newcastle, Sydney and the Upper Hunter regions. One component of the initiative was distributed energy storage systems (ESS).

This case study does not represent a commercially viable PPP model, but some interesting lessons can be extracted from it. In-depth research, including extended interviews with key responsible staff, revealed that the project was a research and development trial. Benefits of the technology were dispersed among the utility (Ausgrid) and consumers. Costs were shared by the government, the utility and, to a much lesser extent, the private provider of

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the batteries. The main reasons the battery provider was willing to bear some costs was to test the technical performance and usefulness of the battery. A key part of the contract with the battery provider required the utility to return the batteries to the battery provider, so that the physical characteristics of the batteries could be analyzed after the trial was complete. The services of the ESS technology therefore could not be provided on a stand-alone basis independent of the government and the utility.


The key stakeholders in the project were the Australian Government as the funder of the SGSC initiative, Ausgrid as the operator, Redflow as the ESS provider, and the customers. A summary of the agreements between stakeholders in shown in Figure 3.4.

Figure 3.4: Contractual Agreements Between Key Stakeholders

The Australian Government awarded Ausgrid AU$100 million for an initiative called Smart Grid, Smart City (SGSC). In return they received information of the effects of smart grid technology.

Before the SGSC initiative, Ausgrid was already carrying out a AU$500 million intelligent network program. The SGSC grant was additional to this existing program but enhanced some of the activities Ausgrid was already carrying out. These enhancements were in line with the public benefits of the SGSC program. They included more rigorous monitoring and public reporting of data from the different technologies, wider economic cost benefit analysis of the projects (beyond only costs and benefits to Ausgrid) and targeted deployment in specific areas.

Through a competitive tender, Redflow was appointed by Ausgrid to provide and install 60 energy storage systems to customers. These Redflow ESSs were part of the SGSC project, that is additional to Ausgrid’s existing intelligent network program.

Customers received the ESS free of charge, and in some cases were paid AU$150 for the site space for the ESS. Ausgrid maintained full control over when and how the ESS absorbed and distributed energy.

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The Australian government’s incentive for the grant was to research the effects of different technology and develop the technology further that would create wider economic benefits. Economic benefits included benefits to customers of shifts in peak to off peak energy consumption and wider benefits to the environment. Therefore, the government was less concerned with peak shaving targets, and more interested in measuring the effects of different technologies.

Information about smart grid technology given to the government also helped them plan for future regulation of the electricity market.

Ausgrid aimed to cover costs with the intelligent network program, however, the main incentives were to develop the technologies and be a market leader. As Ausgrid was already investing in the technology, the SGSC grant helped cover costs and decrease project risks. The project was not driven by a project-specific financial return target.

The customers were attracted to sign up by the novelty of participating in the trial and in some cases by the small AU$150 payment. There were no energy savings guarantees associated with having the ESS. In some trials, customers used the ESS load in peak times, which reduced their energy bill. In other trials Ausgrid released the energy back into the grid at peak times so the customer did not benefit.

In other countries, such incentives may not be sufficient. The ‘novelty factor’ may need to be supplemented by demonstrated energy cost savings or a compensating fee for installation and use. Alternatively, ESS can be combined with a solar panel, to enable the customer to store self-produced energy and also inject it back into the grid.

Technical Specifications

RedFlow’s ESSs are based on its core zinc bromide module (ZBM) flow battery technology. Each ESS contains one ZBM, battery management system (BMS), remote terminal unit (RTU), inverter and 3G modem for communications. All components are housed in a metal enclosure installed near customer houses on private property. This meant that the ESS could be remotely controlled.

The trials showed that the potential customer value from the technology is highly dependent on battery characteristics such as discharge/charge efficiency, storage capacity and control functionality. In the location of the Ausgrid trials, there are two peaks a day in winter, so the batteries needed to be able to charge and discharge in shorter time frames. Discharge/charge efficiency can greatly influence the benefits of ESS.

Correctly predicting network peaks is crucial to effectively using batteries for peak demand management. The use of RedFlow’s ESS reduced the traditional peak seen by the grid by 10-15 percent when used in a ratio of approximately one ESS for 16 customers. While the ESS are effectively reducing the traditional evening peak, they are not addressing the actual peaks seen by the grid from automatic hot water systems that are set to charge at 11pm. The predictability of network peaks is generally better for larger sections of the distribution network.

3.5 Emerging Trends for Smart Grid Technology and Private Sector Investment in Selected Countries

Smart grid technology coupled with private sector investment is emerging in positive ways in a number of countries. Many countries have adopted initiatives to promote smart meter technology through state support and private sector partnering. Two examples of the emerging trends in smart meter and distribution hardware roll-outs are in Mysuru, India

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and Mexico. EVs and associated smart grid charging infrastructure are also developing rapidly. In China, EV numbers have grown fast are and EV charging infrastructure investments are a national economic priority.

These general trends towards more smart grid technology and increased private sector involvement fall short of being true PPPs in the way defined in this report. The long-term benefits from smart meters have not yet been fully realized, and any current benefits almost exclusively flow to the utility or the customers. In future, additional streams of services that smart meters provide may be realized, such as ADR and voluntary curtailment. It is possible that some of these benefits can flow to a private provider separate from the utility. This may enable private sector participation via PPPs in those countries under one of the other models identified in this report.

Smart meter and smart hardware investment in developing countries

Mysuru is the first city project in India to implement a smart grid project under formal contract. The project is a partnership between Chamundeshwari Electricity Supply Corporation (CESC) and India’s Ministry of Power. The overall project cost is $62 million, with the Ministry funding 50% of the investment. The project involves advanced metering infrastructure (AMI) rollout across 24,532 customers, 580 irrigation pumps and 504 distribution transformers. The objectives of the project were to enable identification of faults, asset condition monitoring, better load forecasting, and peak load management through load curtailment.

In Mexico, a large-scale electricity meter replacement programme is underway to enable remote monitoring and outage detection. Comisión Federal de Electricidad (CFE), the largest utility in the Central America and Caribbean region with more than 35 million customers, has rolled out the technology in its east and south-east regions. CFE contracted with Honeywell to deploy more than 200,000 smart electricity meters along with communications devices and software analytics tools to seven cities in those regions.

Both the Mysuru and Mexico projects involve electricity utility procurement of smart meter technology from private sector technology companies. The procurement generally involved close collaboration between the utilities and private sector technology companies. The private party provision was on a commercial procurement of goods basis (with related maintenance and support services), but no performance risks were taken by the private sector.

The smart meters in Mysuru and Mexico themselves provide the ability to better diagnose system faults and issues, and predict and control demand. The benefits of the technology are potentially widespread and occur throughout the electricity value chain. Economic benefits of the technology can accrue to the utility by reducing the need to invest in new generation or distribution capacity. Consumers also benefit from reduced electricity bills if consumption can be reduced at peak times. Furthermore, in Mysuru, rebates were made available to retail consumers that reduced consumption at pre-warned peak times. However, no ongoing benefits accrue to the private provider of the smart metering technology.

EVs and EV charging infrastructure developments

In China, EV charging technology has rapidly emerged in the urban areas of Beijing, Shenzen and Taiyuan. This has accompanied the high growth in EV sales. China had more EVs that the rest of the world combined as of the end of 2017. The EV growth is driven in part by attractive consumer subsidies and license plate fee exemptions. The Chinese Government’s ambitious “Made in China 2025” initiative to comprehensively upgrade Chinese industry includes EVs and EV infrastructure as one of the ten priority sectors.

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This will significantly change the market dynamics across Chinese electrical grid systems, with the power demand profile changing as EV, and their batteries, become more ubiquitous. Smart grid technology in charging infrastructure can enable the control and regulation of power demand from EV batteries, shift load and may even be able to stabilize intermittent VRE sources.

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4 Recommendations for Application of PPP Models

This section sets out recommendations for how the lessons from the smart grid case studies can be applied in developing countries. There are significant and rapid technological developments in electricity grids that present opportunities for improved outcomes. However, a number of prior conditions needs to be met in order to apply PPP contract methods to scaling up the uptake of smart grid technology.

While none of the case studies represent off-the-shelf models that can be directly replicated in developing countries, the case studies present structural ideas that would enable PPP models which would work in developing countries. The models need to be economically viable, that is present a discrete set of benefits which can be captured, for a certain cost subject to risks that are definable. The models also need to apply in the regulatory frameworks that exist in developing countries.

The general theme that emerges from the case studies is that PPP models for smart grid technologies need to provide utilities with straight-forward and reliable solutions, transferring the management of technological complexity to the private sector. In particular, smart grid PPPs are best placed to solve the issues posed by VRE, presenting the utility with reliable net supply of energy while using private sector incentives and the ability to finance new technology to manage the variability. In a sense, the proposed smart grid models would appear to the utility as largely indistinguishable to conventional dispatchable IPPs.

To turn examples into workable models that can be applied in developing countries, PPP models must have risk allocations which are consistent with the capabilities and expectations in developing countries. Developing country utilities generally expect dispatchable energy with high degree of reliability and have limited internal capacity to manage variability. Hence, the proposed smart grid PPPs focus on how the entire risk of managing variability can be transferred to the private sector. In addition, commercial arrangements under the PPP contracts—such as the relationship between a VPP operator and owners of VRE resources discussed below—can correct for poor regulatory incentives and the absence of efficient tariffs. For example, a VRE operator can internally remunerate its participants on time-of-use basis even if the utility does not have time-of-use tariffs.

Like the existing IPP contracts in developing countries, these PPP models will face issues of credit worthiness of off takers. The same approaches as are currently used for credit enhancement in markets with IPPs should be adopted. For example, the use of partial risk guarantees by IFIs and other credit enhancement measures could be targeted at smart grid PPPs with the objective of maximising the uptake of VRE.

4.1 System Stability Services from Battery Storage Providers

A smart grid PPP for system stability services could be deployed in a developing country under a model where a private battery company contracts with the utility to supply such services. In developing countries, many utilities tend to be more focused on meeting increasing demand for energy from their customers than on maintaining power quality. For example, in networks serving primarily residential loads, there may be more tolerance for frequency variation than would be acceptable in systems serving heavy industrial load. However, we anticipate significant demand for system stability services in developing countries dealing with increased penetration of VRE:

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▪ Even if there is tolerance for frequency variations, high penetration of VRE without stability support may lead to gross system instability, including involuntary shedding

▪ Increasing industrialization and urbanization in developing countries will drive demand for high quality power supply

▪ Investments in system stability services through battery storage will enhance the utilities’ ability to satisfy growing demand for energy, as storage will prevent “spilling” of generation by renewable sources.

Moreover, as described in Figure 4.1 below, securing system stability services from an integrated entity that combines VRE generation and battery storage will enhance this model and ensure both the availability of additional energy and improvement in system stability.

4.1.1 Structure of the model

Developing country utilities conventionally manage their system variability by limiting entry of VRE. The objective of this model would be to provide the utility with a standardized tool which would help address system variability caused by VRE and therefore encourage the utility to be more open to VRE. In the process of enabling greater system stability, the utility will also have the option of directly securing additional energy by packaging battery storage with additional VRE generation.

The contract would be modeled on grid auxiliary contracts in wholesale spot markets but would be developed as a direct contract that does not require the existence of a wholesale market.

In a wholesale market, the battery service provider would have an incentive to charge the battery efficiently during periods at which wholesale prices are low. In order for such a contract to work in a setting without a wholesale market (and frequently without time-of-use pricing), there would need to be an arrangement in place for efficient re-charge. This can be achieved either by bundling battery service with an existing generator or providing a side contract for re-charging at specified times when a nearby generator is expected to be underutilized.

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Figure 4.1: Summary of System Stability Services Model

Figure 4.1 illustrates two models. Model 1 is a possible smart grid PPP model. Model 2 shows a model where a generator has integrated a battery into its plant to enable provision of system stability services. Model 1 is viable as a PPP option. Model 2 would more likely occur as part of an IPP's range of services in a PPA. Model 2 would be attractive to utilities that are more focused on meeting additional demand than on ensuring system stability.

In Model 1, the battery company would contract with a conventional generator to secure load to charge the battery. It would then in turn contract with the utility to provide standing ability to rapidly supply system stability services for a fee. The battery company would be remunerated on the basis of a capacity fee, hence providing it with stable cash flows. This would make the project bankable in principle. However, multilateral involvement to cover credit and technology risks could substantially reduce the costs of this service, leading to greater uptake of VRE.

The battery company would bear the risk of meeting the technical requirements for system stability services. It would have to manage this in its procurement of load to charge the battery. The utility benefits from procuring system stability services without needing large investment in new generation capacity (for example a rapid peaking facility). This converts the systemic problem of very short-term grid reliability into a technical problem that the battery company can resolve.

One complicating factor for Model 1 is that technical electricity system rules can tend to limit the provision of system stability services from new technology. For example, grid codes may define dispatchable capacity in terms of thermal generation capacity and thus fail to recognize the dispatchable service that can be provided by a battery. However, this is primarily a problem where technical rules are complex and difficult to change in the

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short-term.18 Many developing countries have the advantage of not having sophisticated rules or any such rules because power systems are vertically integrated under a state-owned monopoly and there is no need to specify technical requirements for ancillary services from third parties. In those cases, the PPP contract between the private party and utility can address the specific requirements for stability services, without the need for regulatory changes.

4.1.2 Technical requirements

The main technical requirement for system stability services provided by battery relate to measurement of frequency. Firstly, frequency must be measured at the battery, in a manner that is verifiable to both contractual parties for the purposes of determining contractual performance. Secondly, the battery operator must receive clear communication when it is required to respond with frequency, both up and down.

Accurate measurement of frequency is critical for the performance of both parties. Without accurate frequency measurement, the battery operator cannot respond, and the utility cannot ensure that the battery operator has complied with its demands.

Clear and rapid communication of the specific requirements are also important. In situations when frequency is required by the grid, the battery operator must know to discharge rapidly. In situations where the system has too much energy, the battery can draw in frequency. Accordingly, the power utility’s operation system must be able to provide this communication to the battery operator.

In addition, the battery operator will have to measure the small energy losses it incurs between the charge phase and discharge phase. This will enable it to ensure it can recover these losses through the contract, as long as the relevant provisions are made in the contract.

Finally, the battery operator will require commercial contracts with generators (or the utility itself) to recharge in periods following discharge to meet its obligations to provide stability services.

4.1.3 Risk allocation and financing

System stability services are costly, especially in situations where they are required as a stand-alone service. Where benefits accrue depends on the form and cost of energy sources. This corresponds to where financial risk is allocated.

The utility, and participants in the wider system, benefit as it becomes more stable. However, where these services are necessary to accommodate DERs and VRE, and where those forms of energy are more expensive than conventional energy, utilities will require additional support for the cost. In these situations, the payment risk will require external support, in the form of a credit enhancement facility.

In situations where DERs and VRE are cheaper than existing sources, the utility ought to be able to pay for the required additional system stability services more easily. The amount of the reduction in overall energy costs to the utility will be reflected in its ability to pay

18 An example of such a situation is the Hornsdale Power Reserve Battery Energy Storage System provided by Tesla in

South Australia. While it has very successfully provided ancillary services, the incentives to do so, and the opportunities to maximize the input of batteries in ancillary services, will require adjustment to the FCAS rules. This is mainly because the existing set of technical rules does not recognize the sheer speed of responsiveness of batteries, and therefore such speed cannot be rewarded. Source: Initial operation of the Hornsdale Power Reserve Battery Energy Storage System (April 2008), Australian Energy Market Operator, available at: http://energylive.aemo.com.au/Innovation-and-Tech/-/media/45ACDCBA73CE46A585ACBFFB132EF9B0.ashx

http://energylive.aemo.com.au/Innovation-and-Tech/-/media/45ACDCBA73CE46A585ACBFFB132EF9B0.ashx

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for system stability services. The greater the reduction in energy costs, the greater the ability to pay for additional system stability services.

The technical risk will be borne by the private party, to the extent that the PPP contract reflects the requirements necessary to provide sufficient stability services. The private party must ensure that the battery is technically capable of meeting the demands placed on it under the contract, and actually does so when required. Penalty provisions can be imposed to incentivize the private party to have readiness.

The private party will be remunerated for two services. Firstly, the available capacity of stability services, which will be by the far larger payment, Secondly, the small amount of losses it will suffer between charge and discharge of the battery.

Finally, the private party will bear the risk of managing an optimal charge and discharge profile so that it can ensure it is ready to meet stability demands, as well as its arrangements to ensure it can charge the battery when needed. The private party will also bear the operational risk of the battery not functioning as expected.

4.1.4 Pre-requisites

The implementation of this model will require coordination with an investment program that incorporates a significant proportion of VRE. The procurement regime that enables VRE investment must be in place. In addition, since battery storage services will be affected by transmission and distribution network constraints, utilities will need to undertake network planning to ensure that battery service suppliers are appropriately located and fully integrated with the network design. In other words, the identification of technical need and the specification of services will need to be driven by the utilities rather than by the investors.

On the regulatory side, the system stability contracts will require regulatory rules that allow the costs of such services to be recovered from the customers or from a direct subsidy by the government.

4.2 Coordinated and Automated Demand Response Model

Figure 4.2 shows a summary of how a PPP model for ADR services could be implemented in developing countries. This model is different to the Californian Honeywell case study in that under the proposed model an aggregator always acts as intermediary between the utility and mid- to large-sized customers. The aggregator effectively carries all of the variability risk from its various customers and can offer the utility a certain amount of negative load at peak times or when otherwise required.

This recognizes that the utility in question is unlikely to have the institutional capacity to attempt to act as a demand aggregator itself. It needs a simple output from the third-party aggregator—a large, firm amount of peak load that can be curtailed when needed. Figure 4.2 illustrates this.

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Figure 4.2: ADR Model Summary


Under this model, the aggregator contracts with the power utility for a certain amount of negative load. The aggregator procures the technology to enable curtailable load at each customer’s site. This will also involve an energy audit (to ascertain the potential curtailable load) and installation of the technology at the site.

The utility pays the aggregator for two types of services:

– Availability of its services (that is, when the aggregator stands ready to provide load curtailment services)

– Utilization of its services (that is, when the aggregator has to deliver load curtailment).

The aggregator could pay its customers a fixed fee, a share of its fee from the utility or simply the benefit of energy savings. The mix of these benefits will depend on the site-specific energy costs, and the economic consequences of the customer’s reduction in energy use (for example if production is reduced as a consequence of load curtailment). Site-specific energy costs will also depend on the electricity pricing model that applies. Where there is peak pricing, a reduction in energy use is likely to be a good incentive to

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participate, due to the energy cost savings. Without peak pricing, customers will require a fee for every kW of curtailable load.

The contract between the power utility and the aggregator resembles a contract between a power utility and an IPP. Contracts used for IPPs have a risk profile that power utilities in developing countries are familiar with and able to execute without significant difficulty.

External finance can be utilised to fund the aggregator. The technology and associated services (audit and installation) can have high upfront costs, which likely require upfront financing.

Credit enhancement facilities can also be deployed in the model. This form of ADR, where load is curtailed, can promote sustainable development goals as both immediate energy consumption is lowered and additional investment in peaking capacity (which can often be GHG emissions intensive) is deferred or avoided.


The model utilizes technology that is well-developed in the market. For example, Honeywell’s technology (and Honeywell is just one of a number providers of such technology) is deployed at over 1.5 million sites worldwide and relied upon for rapid load curtailment. The Honeywell unit installed at sites is the size of a 15-inch computer. However, the technology and its installation and maintenance is not common in developing countries. Additional technical support resources might be necessary.

Furthermore, the viability of this model assumes that the premises where the technology is installed has sufficient capacity to curtail load. These are typically commercial sites such as retail, offices or packaging facilities. The application of the technology will therefore likely be limited to cities and more developed parts of developing countries, where industry is present and there is high interconnection.

Finally, the model will first require an extensive site audit and energy shedding design plan at each site. This enables the aggregator to form a detailed understanding of the site and its potential for load curtailment.

4.2.3 Risk allocation

Risk under this model can be divided into technical and financial risk.

The technical risks are mainly borne by the private party aggregator. It must ensure that it procures the smart grid technology from a technology provider that works, and keeps working. This means the system must be reliable and appropriate maintenance carried out. It also means that the aggregator must ensure that the energy audits and load curtailment plan are accurate and realistic.

Most importantly, the aggregator must ensure that it secures enough curtailable load from its customers so that it can respond to the contractual demands from the utility. In developed countries,19 aggregators that have fixed commitments with utilities will typically secure 1.5 to 2 times the negative load amounts from its customers. In a developing country, the amount would be somewhat higher, due to lower reliability of the end users meeting their obligations and lower enforceability of those obligations.

The utility has a smaller risk to ensure that it contracts for sufficient curtailable load to maintain system stability. The utility will likely be aware of the peak demand profile and

19 For example under typical committed load curtailment contracts in the United Kingdom, the fixed commitment with

a utility is matched by 1.5 times that amount under flexible load curtailment contracts with customers (that is, the customer may opt out).

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can manage to specify this accurately in the contract with the aggregator. Alternatively, technical assistance could be provided to help the utility accurately estimate the amount of curtailable load that should be procured.

Financial risk is managed by the aggregator. It must ensure its commercial arrangements with customers are sufficient to enable it to earn a profit on the payments from the utility, after meeting its financing costs, the costs of the technology and any payments to customers. It also bears a financial risk of penalties for failing to deliver the contracted amount of curtailed load.

Finally, power utilities may need grant subsidies from donors. In the case study, there was a significant gap between the amount the utilities were willing to pay for the curtailable load and the cost of the technology. This was in the region of $200-300/kW and the gap was covered by the grant from the Department of Energy.


The key pre-requisite for the implementation of this model is that the cost of coordinated and automated demand response needs to be lower than the cost of additional generation. This will depend on three key factors:

▪ The cost of additional generation. Despite falling costs of VRE, the cost of peak generation remains high, and is likely to increase. Hence, utilities willingness to pay will increase over time

▪ The cost of technology and the amount of negative energy that needs to be contracted to deliver reliable demand response. While the cost of technology is falling, the cost remains highly sensitive to the amount of negative power that needs to be contracted. This depends, in part, on the pattern of power use by businesses, i.e. do they have the demand that can be curtailed. In many developing countries, a high proportion of demand is derived from air conditioning. This demand is constant and can be easily curtailed for short periods of time without significant inconvenience. Hence, even though in some cases costs may be high, there could also be low cost opportunities

▪ Users’ willingness to curtail demand. How much remuneration users need to receive to be willing to curtail their demand will depend on the value of energy to them. While it may be difficult to interrupt industrial processes, in general there is likely to be relatively high willingness to curtail air conditioning.

Greatest opportunities for coordinated and automated demand response are anticipated in urban settings with significant load associated with shopping malls and office buildings.

4.3 Virtual Power Plant Model

The VPP model is very similar to the Automated Demand Response Model, in that it imposes an intermediary between the utility and capacity providers or curtailable load providers. In the same way as that model, the VPP provides the utility with a fixed amount of capacity (and potentially also system stability services) in exchange for payment. The VPP can combine battery storage, VRE, gas generation, as well as ADR (curtailed load). A summary of the VPP model is presented in Figure 4.3.

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Figure 4.3: VPP Model Summary


Under this model, the VPP contracts with the power utility to provide fixed capacity in exchange for a fee. It is similar to the obligations for providing electricity and conversely payment under a PPA with an IPP. The VPP operator aggregates customer generation, VRE, storage, and curtailable load and sells a package to the power utility, suffering penalties if they fail to deliver the agreed capacity. This model provides the power utility with a level of firmness commensurate with a conventional PPA. As a consequence, the power utility’s level of system risk remains the same, yet the generation is being provided by a combination of sources that, when utilized separately, would each increase system risk.

The VPP must then manage the firmness it is obliged to deliver to the power utility by combining sufficient reliability and diversity from generators, batteries and load curtailment options.

The VPP operator will procure the smart grid technology to be installed at the various sites to enable the rapid communication necessary to provide the balancing functionality to deliver the firm capacity that the VPP is contractually obliged to provide.

Under this model, the World Bank would act as a credit enhancement provider for the power utility to enable it to procure the VPP services. The credit enhancement facility

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could be linked to the VPP procuring lower GHG emitting energy sources, or advancing other sustainable development goals.


The technical requirements are the installation of smart grid communication and management technology at each of the sites providing capacity or curtailed load. The VPP must procure the technology and its installation and maintenance.

The VPP must also manage to supply energy on demand within the same network node in which it is demanded. This means the VPP must have a good understanding of the demands across the grid and the individual network nodes.

Finally, and most importantly, the VPP needs to provide capacity that is firm and available under the specifications agreed. The requirements would be similar to those set out for an IPP in a PPA.

4.3.3 Risk allocation

The risks under this model are divided into technical and financial risks.

The technical risks are mainly borne by the VPP. The essence of this model is that the power utility can convert a material part of its system risk into a technical risk, which it can then outsource to a private party—the VPP.

The VPP must ensure that its smart grid technology can reliably communicate and coordinate the various capacity sources together. It manages this risk through the relationship with the technology provider.

Financial risks are borne by the VPP, as it faces contractual penalties for failing to deliver its firm capacity obligations. The VPP will face these risks at the PPP procurement stage, when it needs to identify the sources of capacity it could utilize. It will also face this risk for the life of the PPP contract as it matches its obligations to the power utility with the capacity providers.

There will be incentives for VRE producers, storage providers and other capacity providers to invest in capacity where there is sufficient certainty that the power utility will procure VPP services. This makes the World Bank (or other donor) credit enhancement facility even more important. Where a credit enhancement facility is well signaled to the market, providers of additional (sustainable) capacity will be more likely to invest.


The key pre-requisite for the implementation of this model will be the ability of the utility to accommodate multiple components of the VPP within its grid architecture. To enable VPP to deliver the required level of reliability, there will need to be no transmission or distribution constraints between different components. Hence, the utility will need to specify where the components can be located and how they interface with different elements of the network. In practice, this means that the utility will need to have a sophisticated planning capability in order to procure a VPP compared to a conventional IPP.

On the regulatory side, the suggested structure of the contract can be accommodated within any regime that enables procurement of IPPs.

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5 Opportunities for Smart Grid PPPs in Developing Countries

Developing countries increasingly face problems with renewable energy integration and are looking into ways to solve those problems. The smart grid models we have looked at are the next generation of dealing with grid integration problems.

The previous section described some PPP models for smart grids that could be suitable for developing countries. This section of the report identifies markets where the PPP contract models could be practicably feasible and would have the ability to solve key issues for the power sector.

The study examined the market structure across a wide sample of countries to assess whether PPP contract models are practicably feasible. Specifically, three criteria were applied:

▪ The power sector is sufficiently liberalized to allow private sector participation. Full reform would probably already incentivize private sector participation (without a significant role for the public sector)

▪ There is a creditworthy (or with potential credit enhancement) vertically-integrated utility/utilities(or something close to one)

▪ National or significant utility/operator with experience in procuring from IPPs. If the utility is familiar with IPP models, they are likely to be comfortable with the PPP contract models.

To determine whether the PPP contract model will solve real issues, the level of RE in each country and the amount of RE planed in the future were assessed. Having high or RE can highlight different issues that can be solved with smart grid technology. For high, or rapidly increasing, levels of VRE, integration is often a key concern. For low levels of VRE, it is possible that they are waiting for integration solutions before allowing the market to invest in this type of generation. Countries with low VRE have an opportunity to skip development stages and go straight to high levels or VRE with smart grid solutions.

Some developing countries have already developed smart grid policies and are already using smart grid technologies.

In Colombia, solar and wind energy are currently underdeveloped, with approximately 30MW of installed capacity, almost all of which is wind power. However, Colombia has built a comprehensive policy and regulatory framework to enable and promote RE and smart grids. The government has made a clear and credible commitment to diversifying generation sources, and particularly from non-conventional renewable energy (NCRE) technologies such as solar, wind, geothermal, and small hydro. In addition, the government and large electric utilities have been exploring the potential for deployments of smart grid technologies to control system losses, defer investments in expensive peaking generation, and to improve operational efficiencies.

In Costa Rica, the Government-owned electric utilities have well-developed smart grid roadmaps aimed at controlling system losses, deferring investments in expensive peaking generation, and improving operational efficiencies.

Costa Rica’s National Energy Plan, created in 2011, created favorable conditions for RE. Regulation relating specifically to smart grid is less developed. But through the state-owned utilities ICE and CNFL, the government has promoted smart grid through the following activities:

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▪ Smart meter pilot projects at ICE, CNFL, JASEC, and ESPH

▪ Completion of Smart Grid Maturity Model at CNFL, establishing baselines and targets for large-scale smart grid deployments

▪ GIS mapping throughout the CNFL service territory

▪ SCADA throughout the transmission grid.

In Jamaica, The Jamaica Public Service Company Limited's current budget includes $49.2 million for smart grid investment from 2015 – 2019, with spending focused on reducing non-technical losses, reducing technical losses, and improving reliability through AMI metering and distribution automation.

Overall, many developing countries are moving to introduce smart grid technology. In many cases, this will not require PPP projects. The examples below represent an initial survey of markets where greatest opportunities exist to promote the uptake of smart grid technology through the PPP models developed in this report.

5.1 Latin America and the Caribbean

5.1.1 El Salvador

Market Structure

Power Sector Regulatory Framework- Private operators own most of the distribution network, and are increasingly participating in generation as well. Generation is largely de-regulated, but hydroelectricity generation is still dominated by a single state-owned company, the Executive Hydroelectric Comission of the Lempa River (Comisión Ejecutiva Hidroeléctrica del Río Lempa—CEL). In general, however, there is strong competition in generation, with electricity sold through with retailers and end-users, and on a well-established spot market. A single state-owned company transmits all electricity, and privately held companies distribute electricity under three separate concessions.

Creditworthiness- The utilities are credit worthy.

Experience with IPPs- The regulatory framework is structured to encourage private investment. Privately owned entities make up 45 percent of electricity generation on the Salvadoran grid. Duke Energy has the largest share of electricity generation of any private entity, at 16 percent. publicly owned entities make up the other 55 percent, including nearly all electricity from geothermal and hydropower.

Opportunities for smart grid technologies

The Government’s strong fiscal incentives and policy commitment to renewable energy sources make the electricity sector particularly ripe for smart grids.

Generation from renewable sources already accounts for more than half of electricity generation on the national grid, and just under half of the installed capacity in El Salvador. The RE is predominantly hydro and geothermal.

Existing solar and wind generation is low, but technical potential is high. The National Energy Board’s generation projection includes ten solar projects, with a combined capacity of 171MW, and two wind projects, with a combined capacity of 40MW.20

The new solar and wind projects will need to be effectively integrated into the system. As they are variable energy sources, battery storage may be required. A VPP could be an

20 Consejo Nacional de Energía. “Actualización del Plan Indicativo de la Expansión de la Generación 2014-2024.”

December 2014. http://www.cne.gob.sv/index.php?option=com_phocadownload&view=category&id=4&Itemid=288

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effective way of integrating these energy resources. A PPP model transfers the technical risk of operation to the private party. The intermittency risk, and management of multiple resources is transferred so that the private party is incentivized to ensure stable load.

5.1.2 Dominican Republic

Market structure

Power Sector Regulatory Framework- The Dominican electricity market is characterized by competitive generation and state-owned transmission and distribution networks. Privatization of the generation and distribution segments occurred in 1999, although between 2003 and 2009, the three distribution companies were renationalized as a result of macroeconomic challenges and rising power prices. Generators may sell their electricity to distribution companies, unregulated clients, or on the spot market.

Creditworthiness and Experience with IPPs- We have drawn information from our Caribbean energy database to determine is the Dominican Republic has experience with IPPs and if the utility is credit worthy. In our database, we have answered “yes”, “no”, or unclear for these three questions:

▪ Are there workable precedents or rules for PPA terms and grid operation rules?

▪ Are there clear and effective licensing processes and requirements in place for IPPs?

▪ Is the off taker credit-worthy?

The Dominican Republic had “no” for the first two questions to do with IPPs and “yes” for creditworthiness. The results indicate that IPPs are not common place which may be a barrier to implementing a smart grid PPP model. If the Utility is not familiar with IPPs, a smart grid PPP contract, even simplified to look like an IPP, may be overwhelming.

The utility not being comfortable with the contract could be a barrier. However, if this barrier could be overcome, there is a lot of potential for smart grid PPPs to be incredibly useful due to the high levels or RE (discussed next). For this reason, we have kept the Dominican Republic in this pipeline of opportunities.


The Dominican Republic has approximately 20 percent RE generation. This is expected to increase by 25 percent in the next five years. 21

The Dominican government has signaled a clear national policy of supporting non-conventional renewable energy technology by granting fiscal incentives (such as tax credits, exemptions, and waived import duties) as well as establishing regulatory structures (such as net metering and streamlined interconnection rules) to enable utility-scale and distributed generation.

There are no relevant regulations specifically regarding smart grid. However, the renewable energy regulations will drive a need for smart grids to help mitigate the variability of renewable generation. Smart grids could also help with current grid reliability issues. A PPP model would allow effective integration of these diverse energy resources. The technical risk of operation is transferred to the private party. The intermittency risk, and management of multiple resources is transferred so that the private party is incentivized to ensure stable load.

21 Castalia Caribbean database 2017

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Smart grids would be technically viable in the Dominican Republic. The system operator is already in the process of deploying supervisory control and data acquisition (SCADA) to nearly half of its territory and the transmission company Empresa de Transmisión Eléctrica Dominicana (ETED) already has a fiber optic communications network. Most homes and businesses are located in close enough proximity to use a RF wireless mesh communications network for smart metering.

Smart grids would also be economically viable due to opportunities to improve on the current: high frequency service costs from other sources, high rates of outages, and high distribution losses.

5.1.3 Other Caribbean Islands

We group together Caribbean islands because they all deal with similar challenges and have similar market structures.

Market structure

Power Sector Regulatory framework- All the Caribbean islands have a single national utility that is financially secure. There have not been market reforms because they are too small to disaggregate.

Creditworthiness and Experience with IPPs- As we did with the Dominican Republic, we have drawn information from the Castalia Caribbean energy database to determine which countries have experience with IPPs and have creditworthy utilities. In the Castalia database, we have answered "yes", "no", or "unclear" for these three questions:

▪ Are there workable precedents or rules for PPA terms and grid operation rules?

▪ Are there clear and effective licensing processes and requirements in place for IPPs?

▪ Is the off taker credit-worthy?

Countries with yes to all three are likely to be good candidates. The only countries with yes to all three are:

▪ Barbados

▪ Grenada

▪ St. Kitts

Jamaica also scored yes to all three questions, however, as discussed at the start of this section, Jamaica has been excluded as they are already progressing with smart grids independently and are unlikely to need assistance.

Problems that smart grid PPPs could solve

All three of the countries that fit the market structure criteria have relatively low levels of RE currently (see Table 5.1). However, if RE generation increases rapidly, the smart grid PPP models would help with integration.

Barbados has a significant amount of RE generation planed in the next five years (see Table 5.1Table 5.1: RE Production and Planed RE Production

Barbados Grenada St. Kitts

Share of RE to total electricity produced 5% 1% 2%

Total electricity produced from RE (MWh/year) 41,342 2,850 2,929

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Total planned electricity production from RE (MWh/year)

35,390 - -

Source: Castalia Caribbean database 2017

). However, neither St. Kitts nor Grenada have any RE generation planed that we could find. Projects are considered planed if the utility has given it at least 50 percent chance of coming online within 5 years. The lack of RE projects could be due to concerns with integration that have led to policies which discourage RE. The smart grid PPP models can be used to address these concerns.

Table 5.1: RE Production and Planed RE Production

Barbados Grenada St. Kitts

Share of RE to total electricity produced 5% 1% 2%

Total electricity produced from RE (MWh/year) 41,342 2,850 2,929

Total planned electricity production from RE (MWh/year)

35,390 - -

Source: Castalia Caribbean database 2017

5.2 Africa

5.2.1 Ghana

Market structure

Power Sector Regulatory Framework- The government is in final negotiations with a preferred bidder for a concession to operate the national utility, ECG. This means the criteria of a semi-reformed utility would not be met. However, it is unlikely that Ghana would adopt smart grid technologies independently, even with the utility under a private operator. We therefore put forward that Ghana can still benefit from the smart grid PPP models. The new private operator, with support from a donor or the government, could sign a contract with another private company for smart grid services.

Creditworthiness- The main distribution company, the Electricity Company of Ghana (ECG), struggles to fully recover its costs. As a result, there are credit worthy issues. Commercial finance of infrastructure is only possible with central government credit support, which is difficult to secure. Continuing generation shortages make cost-recovery more difficult, while lack of cost recovery makes it difficult to finance additional generation.

The new private operator will need to be credit worthy for other private companies to engage in business with them.

Experience with IPPs- Private finance of generation in Ghana is a well-established model. Several IPPs provide additional generation to the public utility. Takoradi International Company (TICo), Sunon Asogli Power Plant (SAPP), CENIT, are long-standing IPPs operating in Ghana. The on-going power shortages have led to the rapid addition of new IPPs: Karpower barge (225 MW); Ameri Power (250 MW); TICO steam turbine (110 MW); and BXC solar (20 MW)18.

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Problems that smart grid technology can solve

Smart grid services could help solve these reliability issues. After reliable power supply for many decades, power cuts are now an unwelcome but regular occurrence in Ghana, as demand growth has outstripped generation capacity. Even though installed generation capacity has more than doubled; increasing from 1,730 MW in 2006 to 3,795 MW in 2016. Peak electricity demand only increased by 50 percent during this same period, increasing from 1,393 MW in 2006 to 2,087 MW in 2016. 22

Ghana currently has an over dependence on hydro and thermal energy. However, there is also a big push for RE from the Government of Ghana published the Renewable Energy Act (C-SIREA, and ‘the RE Act’) in 2011 and set for the country the strategic goal of generating ten percent of its electricity from renewable energy. In accordance with the RE Act, the Government wants to set RE purchase obligations (POs) requiring electricity distribution utilities and bulk customers to procure a specified percentage of their total electricity purchase from RE.

The Energy Commission have plans to implement a rooftop solar PV program.23 The objective of the program is to provide 200MW of peak load relief on the national grid. The Energy commission have been tasked with helping install 20,000 rooftop solar systems on residential homes. A VPP could help integrate the rooftop solar and decrease the risks for the utility.

5.2.2 Kenya

Market structure

Power Sector Regulatory framework- KPLC is a vertically integrated utility with 50.1% public and 49.9% private shareholding. It is the single buyer in the power market in Kenya, buying in bulk from all power generators. KPLC then transmits and distributes power to customers, so all generators rely on KPLC for their revenue.

The policy and regulatory environment in Kenya is fairly advanced with unbundling and partial privatization of national utilities, and cost-reflective tariffs.

Creditworthiness- KPLC has cost-reflective tariffs, USTDA and Power Africa (part of USAID) provide credit support in addition to the creditworthiness of the utility itself.

Experience with IPPs- KPLC has a high level of sophistication and knowledge with regard to transacting with the private sector. While IPPs have been limited so far, take-or-pay PPAs signed with KPLC support the private sector’s role in electricity generation.


Kenya is highly likely to be very reliant on variable renewable sources in the short to medium term. This presents ideal circumstances for a smart grid PPP intervention that could reduce risk of intermittency.

Power Africa estimate that an additional 2700MW of capacity will come on stream in Kenya in 42 plants by 2020.24 420MW of this amount is projected to be from solar PV. In addition, many of the off-grid diesel stations will be converted to solar hybrids. In the

22 CGD Policy Paper, 2017, The Electricity Situation in Ghana

23 Ghana Energy Commission http://rooftopsolar.energycom.gov.gh/about-nrp

24 Power Africa (2015), Development of Kenya’s Power Sector 215-2020, available at: https://www.usaid.gov/sites/default/files/documents/1860/Kenya_Power_Sector_report.pdf

http://rooftopsolar.energycom.gov.gh/about-nrp

https://www.usaid.gov/sites/default/files/documents/1860/Kenya_Power_Sector_report.pdf

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short term, the Lake Turkana wind power project for 310MW will come online in October 2018.

5.2.3 Senegal

Market structure

Power Sector Regulatory Framework- Senegal’s national state-owned utility is Senelec. Electricity generation is open to the private sector. Senelec, the sole buyer, signs power purchase contracts with independent power producers (IPPs)

Creditworthiness- Senelec is not credit worthy and a guarantee is likely to be needed to attract private sector investment.

Experience with IPPs- Senelec has experience with IPPs. The General Electric/GTI Dakar IPP supplies 20 percent of Senelec’s electricity. The second IPP, Kounoune 1, came online in 2008 and was partially funded by the International Finance Corporation. In 2016 another IPP operator, ContourGlobal, commissioned an 88 MW diesel power plant and a steam turbine at Cap des Biches.


One of the Government’s priorities in the energy sector is to lower the cost of generation by reducing dependence on imported liquid fuels. Currently, Senegal’s electricity source is overwhelmingly diesel and gas, both need to be imported.

Senegal has significant potential to develop solar and wind power. Solar irradiation is above 2,000 kWh/m2/year for Global Horizontal Irradiation across most of the country, with the average global daily irradiation calculated at 5,43 kWh /m²/day, which gives excellent prospects for photovoltaic projects as well as for the use of solar thermal technologies. There is good wind energy potential along Senegal’s Northern coastline between Dakar and Saint Louis. So far, this resource has not been exploited, but it is estimated that wind power could account for as much as 70% of Senegal’s renewable energy generation capacity. 25

Smart grids can help provide grid stability in Senegal. Help with stability will be especially needed if the solar and wind potential is realised. Using a PPP to procure the smart grid technology would decrease risks for Senelec.

5.2.4 Cabo Verde

Market structure

Power Sector Regulatory Framework- The National Electricity and Water Company (ELECTRA) is responsible for supplying electricity in Cabo Verde. ELECTRA is a company held by Cabo Verde Government (85%) and Cabo Verde Municipalities (15%). As an archipelago, each island of Cabo Verde has its own local power station running on petroleum products and its own electrical grid.


There is relatively high uptake of distributed generation in Cabo Verde. According to a study commissioned by the Director General of Energy (DGE), at least 827kWp of DG

25 Africa-EU Renewable Energy Cooperation Programme https://www.africa-eu-renewables.org/market-

information/senegal/renewable-energy-potential/

https://en.wikipedia.org/wiki/Senelec

https://en.wikipedia.org/wiki/Senelec

https://www.africa-eu-renewables.org/market-information/senegal/renewable-energy-potential/

https://www.africa-eu-renewables.org/market-information/senegal/renewable-energy-potential/

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has been installed across the 9 inhabited islands. 26 This includes at least 16 DG systems with a capacity of 214kWp that are officially or unofficially grid-connected. Since the electrification rate in Cabo Verde is close to 100%, it is likely that a high share of the other systems is also installed in places with access to the LV grid; if so, these could be grid-connected if there were an operational net metering framework. In addition, a number of DG systems have applied to Electra for connection to the grid.

Most of the DG is solar. The study commissioned by DGE found that wind is marginal at the distributed scale: there are only 1.9kW of ‘pure’ installed distributed wind DG systems, plus 34.5kW of combined PV-wind distributed DG systems. The study was unable to assess whether these systems are connected to the grid or not.

Cabo Verde has a target of 100 percent renewables by 2020. Total electricity produced in 2015 was 31 ktoe, 87 per cent of which was generated from fossil fuels. However, Cabo Verde has great wind and solar potential. The energy policy target was to use solar to cover 2 per cent of the total energy consumption by 2010, however implementation of this target has been slow. 27

ADR is unlikely to be an option due to very few businesses with high consumption. However, distributed solar, wind, and storage with a VPP could be the way to make progress towards the 100 percent RE target.

5.3 Middle East and North Africa

5.3.1 Morocco

Market structure

Power Sector Regulatory framework- Office National de l’Electricité et de l’Eau Potable (ONEE) is the Moroccan state-owned vertically integrated utility. It covers generation (4,500MW), transmission and distribution of electricity. It has a monopoly on transmission operations and is the sole power supplier to distribution utilities. ONEE is the single buyer for all generation (and imported power). ONEE produced around 42% of electricity as of 2015, with 40% produced by IPPs and 17.4% imported from Spain and Algeria.

Creditworthiness- ONEE creditworthy and likely to support bankable PPP projects. The utility is a World Bank borrower and its 2016 Implementation and Completion Results Report noted that its borrower performance was satisfactory.

Experience with IPPs- Private participation is common in Morocco. A number of IPPs have entered Morocco since private participation was permitted in 1994. Four very large IPPs dominate, including Jorf Lasfar Energy Company (JLEC), owned and operated by the Abu Dhabi National Energy Company PJSC. JLEC runs the largest coal-fired power plant in MENA.


Morocco has a high potential and rising penetration of renewables. There currently significant penetration of wind power (10%). In the near future very significant investments will be made in additional wind and large-scale solar projects.

26 DGE (2016): Inventariação, avaliação e diagnóstico de infraestruturas com base em Energias Renováveis e iluminação solar, draft report

14.4.2016. This number includes only the operational systems on which data could be collected. The draft report is

being updated as of 6 July 2016 with additional information.

27 SE4ALL and the Covenant of Mayors in Africa Workshop (2015) Learning from Cabo Verde’s Renewable Energy plan

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The 2013 energy mix is illustrated in Figure 5.1 below. t

Figure 5.1: Generated Electricity in Morocco by Technology Share, 2013 (percent)

Source: World Bank (2017), Shedding Light on Electricity Utilities in the Middle East and North Africa

Morocco is one of the largest energy importers in the Middle East and North Africa (MENA) region and relies on imported fossil fuels. In this context, the Moroccan government has set an ambitious target of meeting 42% of its energy requirements using renewable resources (2GW solar and 2GW wind) by 2020.

The country has high natural potential for further wind resources. Very significant solar PV investments are slated for the next years. Five locations - Laayoune (Sahara), Boujdour (Western Sahara), Tarfaya (south of Agadir), Ain Beni Mathar (center) and Ouarzazate are being developed with modern solar thermal, photovoltaic and concentrated solar power mechanisms. Ouarzazate will be the world’s largest solar power plant at 500MW when fully completed. As Morocco is the only African country to have a power cable link to Europe (connected to the Spanish grid), possibilities for export are open.

5.3.2 Jordan

Market structure

Power sector regulatory framework- National Electric Power Company (NEPCO) is the national electricity transmission company, the system operator and the bulk supplier (single buyer and seller of electricity). The regulatory structure is such that there are not sufficient incentives for a grid participant to procure smart grid technology to manage intermittency itself.

Creditworthiness- The power sector in Jordan faces two key problems–an inadequate domestic supply of fossil fuels and an insufficiently diversified mix of fuel supply. These

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problems have directly impacted NEPCO’s financial performance. In the last five years, NEPCO has experienced a sharp increase in fuel costs, without the ability to correspondingly increase revenue. NEPCO has accumulated losses of JOD4.6 billion (Jordanian Dinars).28 NEPCO’s poor financial performance has, in turn, deteriorated the financial position of the Government of Jordan.

Experience with IPPs- NEPCO has a lot of IPP experience. Every generator in the past 15 years has been an IPP.


Error! Reference source not found.Figure 5.2 shows the electricity production in Jordan, in gigawatt hours, by type of fuel, from 2007 to 2014. It shows that, between 2007 and 2010, most electricity was produced using natural gas (shown in orange in the figure blow). In 2011, the use of natural gas reduced considerably, and heavy fuel oil and diesel became the most important fuels for electricity production until 2014 (shown in blue and grey). Coal, and “other” sources of fuel (including renewables) together account for less than 1 percent of electricity production.

Figure 5.2: Electricity Production in Jordan by Type of Fuel (2007 to 2014)

Source: NEPCO

The Government has implemented a strategy to diversify the generation mix. Even though oil and gas are likely to remain key sources of fuel used in electricity generation for the foreseeable future, the strategy is likely to lead to an increase in RE.

Since 2011, the Government has implemented a strategy to secure alternative sources of energy. The main outcomes of this effort are:

▪ In the past five years, the Ministry of Energy and NEPCO have signed contracts to procure over 1000MW of renewable energy capacity,

28 JOD4.6 billion is equivalent to USD6.5 billion, using an exchange rate of 1 JOD : 1.41 USD (as of August 4th 2016).

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▪ An LNG terminal was installed in the port of Aqaba in 2015, reducing the country’s reliance on diesel and heavy fuel oil imports,

▪ A signed agreement to develop a 450MW oil shale-fired thermal station.

Jordan has contracted enormous amounts of PV and wind and by end of 2019, it will have the highest penetration of variable energy in the world. Currently, Jordan has significant concern about managing intermittency. Trading energy with neighbouring countries is not an option due to geo-political risk. The energy solutions therefore need to be self-contained.

Smart grid technology could help ease the burden of intermittency as PV and wind come online. Smart grid technology could also help Jordan utilize battery storage as it comes online. The European Bank for Reconstruction and Development is currently carrying out a study to regulate battery storage, including developing a regulatory framework for storage.29

5.4 The Pacific

5.4.1 The Federated States of Micronesia

Market structure

Power sector regulatory framework- Four state-owned utilities are responsible for supplying electricity to consumers in FSM: Chuuk Public Utility Corporation (CPUC), Kosrae Utilities Authority (KUA), Pohnpei Utilities Corporation (PUC), Yap State Public Service Corporation (YSPSC). Each utility is governed by the Utility Board at the state level.

Creditworthiness- In general, the utilities in the FSM are not profitable because tariffs do not reflect full costs. Even though tariffs are relatively high when compared with international standards, they do not allow the state utilities to recover their full operating and maintenance costs, and/or finance new investments. Guarantees may be needed for the private sector to enter into agreements with the utilities.

Experience with IPPs- Pohnpei is the only state in FSM that explicitly incorporates independent power producers (IPPs) into its state law. PUC currently has an IPP arrangement with Vital Energy. While Chuuk does not have an explicit provision for IPPs, CPUC considers IPPs to be permitted under the law. CPUC and Vital Energy are currently negotiating an IPP for Tonoas island.


Although diesel is currently the main energy source on the main islands, RE is planned to increase significantly over the next 20 years (see Figure 5.3). The plan is to use mostly solar generation and battery storage, with diesel used as backup to achieve a high service standard level.

Smart grid technology could be used to coordinate control of renewable generation, battery storage, diesel generation, as well as enabling ADR (especially in for large consumers that are government organizations). The Master Plans for each state recommend an IPP install and operate the new solar and battery systems. The IPP may also be interested in managing the integration with smart grid technology.

29 The EBRD tendered this project in mid 2017: Evaluation of energy storage options and procurement in Jordan

https://www.ebrd.com/cs/Satellite?c=Content&cid=1395256586134&pagename=EBRD%2FContent%2FContentLayout&rendermode=live%3Fsrch-pg%3Fsrch-pg



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Figure 5.3: Planed RE Percentage in FSM

Source: Federated States of Micronesia Energy master Plan, 2018

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%R

E %

Chuuk Kosrae Pohnpei Yap Total FSM

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Appendix A Overview of Global Smart Grid Experience relevant to Development of PPP Arrangements

Many countries are still in early stages of formulating smart grid strategies, often led by the electricity sector regulator. While there have been announcements of strong intentions, such as in Chile and Mexico, for the most part smart grid projects are in early planning stages and those that are being implemented are restricted to small-scale demonstration initiatives

Many aspects of smart grid development are being implemented by the monopoly distribution and transmission utilities without any participation by third-party private investors. In many instances, such developments are promoted and supported by the regulators, introducing elements of “regulatory contract”. However, there are relatively few examples of specific arrangements that would be worth studying in-depth for the purposes of this assignment. International organisations have played an important role in financing the overall transmission investment programs in many countries, including the smart grid elements, but all the examples identified were under programmatic loans to the public sector, rather than in support of PPP arrangements

Given the novelty of the smart grid technologies, a very significant proportion of projects that do involve the private sector are essentially technology trials which involve joint public-private attempts to test and prove the technology

While a number of PPP arrangements in development are identified, it appears that many of them are still in early stages of design. A very significant proportion of projects involves the roll out of smart meters. The World Bank, ADB and IADB have all provided financing for smart meters as part of sector lending. While the scale of the roll-out is significant, there are still few examples of this technology being used to its full benefit. In the OECD markets, households have generally struggled to understand the benefits of smart meters in shifting of their consumption patterns

Many observed examples across the developed markets are of similar type. For example, the United States has the most comprehensive and well-resourced public support for the implementation of smart grid solutions. Since 2009, the Department of Energy has provided more than $3.4 billion in grants for smart grid projects. While hundreds of projects have been implemented, the arrangements for the allocation and disbursement of such grants are identical. Very few grants have been allocated to private sector participants, with the majority going to publicly owned utilities, including municipalities and cooperatives. While the US experience is useful and interesting, it would be unhelpful to list all such projects in the short-listing process.

The following table summarizes the findings of the preliminary research performed for this report.

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Table 5.2: Summary of Smart Grid Survey

Category Country Geographic scale Utility or Entity Description E

nh

anci

ng

Tra

nsm

issi

on

and

Dis

trib

uti

on

Gri

d R

elia

bili

ty

China Widespread For example: State Grid Corporation of China and China Southern Power Grid Company

Three phase smart grid plan involving planning pilot projects, construction and finally upgrading and enhancing.

Various Wide Area Management Systems installed, including PMUs at all generation facilities over 300MW and substations over 500kV.

United States Widespread For example, Southern California where utilities deployed Honeywell ADR technology.

Highly advanced smart grid strategy. Over US$4.5 billion allocated to power grid modernisation under 2009 fiscal stimulus Recovery Re-Investment Act. DoE provided with US$3.4 billion to invest in private sector under Smart Grid Innovation Grants.

Italy Widespread Energy regulator AEEG

Competition-based procedure that provided incentives to smart grid pilot projects related to distribution. Incentive payments of +2 percent return on capital over 12 years, subject to pilot project meeting various cost-benefit assessment criteria.

Nine tariff-funded projects were awarded since 2010.

Romania Widespread, specifically in Brasov

State-owned Electrica SA and private technology firm parnters

Regulator introduced a quality award or penalty factor of +/- 4 percent of allowed revenue to incentivise higher network performance. This resulted in a smart grid pilot project.

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Category Country Geographic scale Utility or Entity Description

En

ablin

g D

ynam

ic

Inte

grat

ion

an

d

Man

agem

ent

of

Po

wer

So

urc

es

Philippines Widespread National Grid Corporation (NGC)

NGC is responsible for securing all ancillary services to maintain grid stability. It has entered into a number of contracts with battery storage providers to provide rapid reaction voltage regulation and power.

Australia South Australia State Government of South Australia, Tesla and Neoen: Hornsdale Windfarm

A consortium of Tesla and Neoen won a procurement contract to provide a 100MW battery farm adjacent to the Hornsdale wind generation facility.

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Germany Widespread RWE and Siemens RWE, a utility, and Siemens, a technology company partnered to create a VPP in Germany that began with 20MW capacity, expanded to 80MW and is planned to expand to 200MW. The VPP was the first, centralised direct marketing of energy form predominantly renewable sources in Germany.

South Korea Jeju Island Various, led by Korean Electrical Power Corporation (KEPCO)

The Jeju Island smart grid project involved a consortium of 168 companies collectively investing US$171 million, with US$68.5 million in funding from the Korean Government.

Part of the project involved the roll out of a VPP business model, with numerous technology companies attempting to commercialise VPP technology.

Following the pilot, the Smart Grid Promotion Act was passed to help coordinate private and public activities.

Japan Miyako-Jima, Okinawa

Okinawa Electric Power Company

Demonstration smart grid project. The existing power grid was linked to a 4MW solar power plant and sodium sulphide battery complex, capable of

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storing 4MW, as well as a 4.2 MW wind farm. The utility invested US$75.8 million in smart grid infrastructure (with two-thirds government subsidy) to enable the effective integration of these sources.

Spain Malaga Enel-Endesa Group Consortium of 11 energy companies and 14 research companies that implemented the Malaga Smart City in Spain. The project successfully integrated low-capacity renewable energy resources (wind and solar) with energy efficiency and remote-control kits at households.

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Australia Newcastle, Sydney, Hunter Valley NSW

AusGrid AusGrid implemented a trial of 61 ESS in the region under a AUD100 million government smart grid initiative. Battery technology was procured from Redflow, an Australian manufacturer of zinc bromide batteries. The ESS were deployed at residential sites and allowed shaving of system peaks.

United States Southern California PG&E, SDG&E and SCE with Honeywell technology

Honeywell financed (with support from the DOE grant) the roll out of customer site equipment and provided on-going operations with a turnkey service. This, together with aggregator services, permitted ADR and therefore shaving of system peaks.

Netherlands Groningen DNL GV Small scale, 42 household, trial enabling both consumer and supplier control of consumer equipment.

Italy Widespread Enel Enel deployed over 30 million smart meters. Consumers had higher levels of information to enable more responsive consumption activity.

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Supply-side load control functions were able to be activated without customer consent.

United Kingdom Widespread Smart Energy GB National roll out of smart meters via utility provider. Costs incorporated into utility asset bases and recovered through tariffs.

India Mysuru CESC Smart grid project under a formal contract (with some PPP features). Smart metering, smart irrigation pumps and smart distribution sets were provided to a small sub-set of the population.

Australia State of Victoria State Government Advanced Metering Infrastructure Program was rolled out compulsorily in Victoria to catalyse various outcomes at consumer and supplier levels. There has been almost no take up of the ‘smart’ features of the meters deployed.

Canada Ontario Government of Ontario

Government-led and mandated roll out of 4.8 million smart meters in all Ontario households and businesses by 2010. Studies found only a 0.7% reduction in peak demand for residential consumers over a four-year period.

Mexico East and south-east regions

Comisión Federal de Electricidad

Federal electricity company procured smart meters from various suppliers, including Honeywell. In the east and south-east regions, the roll out helped to reduce utility costs and enhance service.

France Widespread ERDF Roll out of 28 million smart meters by 2020.

Spain Basque country Iberdrola Distribución Eléctrica

Roll out of smart meters, modernized transformation centers, smart substations and some consumer information services. The modernized grid allowed for various energy saving benefits, as

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well as permitting greater integration of VRE sources in future.

Ecuador Widespread GE Roll out of over 25,000 smart meters commenced in 2011. Objectives were to enable remote connect and disconnect to the grid of customers, efficiency planning and demand side response.

China Widespread Multiple utilities Procurement of 425.8 million smart meters by various utilities.

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Germany Widespread Multiple Since 1991 Germany operationalised two-way flows between the grid and consumers to enable consumers to sell renewable energy back supported by feed-in tariffs.

Denmark Widespread Frederiksberg Forsyning Nissan, Ennel, Mitsubishi and Nuvve

Denmark is the leading vehicle to grid market. Various pilot projects have successfully integrated vehicle-to-grid facilities.

United States Numerous military bases, including Fort Carson

Department of Defense, Department of Energy and a consortium of research, utility and military institutions

The Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) Program for military bases intends to make these more efficient. Projects have integrated vehicles, generators and solar arrays as well as specialised software to micro grid.

Japan Aichi Prefecture Toyota Test of the grid connectivity of 3,100 electric vehicles in the city.

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A.1 Enhancing Transmission and Distribution Grid Reliability

There are numerous initiatives around the world to incorporate smart grid elements into the architecture of transmission and distribution networks. The survey suggests that the biggest share of investment that can be classified as “smart grid” falls into this category. In many instances, such projects involve direct cooperation between governments and government-owned network operators. While the transparency of the subsidy and cooperation regimes varies from country to country, there are few examples of projects that could be described as public-private partnerships for the purposes of this assignment.

China is a typical example of close government involvement in the promotion of smart grids. The Chinese power sector is served by two main publicly owned transmission and distribution companies, the State Grid Corporation of China (SGCC) and the China Southern Power Grid Company (CSPGC) with an 80% and 20% market share respectively. China’s 13th five-year plan allocated 40 billion yuan ($6 billion) to a nationwide smart grid demonstration program.

Under this program, both utilities developed a three-phase smart grid plan. Phase 1 (2009-2010) was for planning pilot projects, Phase 2 (2011-2015) for construction and Phase 3 (2016-2020) is for upgrading and enhancing projects. During the current phase, the utilities installed Wide Area Measurement Systems, including phasor measurement units (PMUs) at all generation facilities over 300MW and all 500kV substations. Successfully completed demonstration projects, designed to automate distribution and integrate smart dispatch and management systems, include

▪ The 750kV smart substation in Yunan

▪ Yu Shan 500kV smart substation

▪ 220kV smart substation in Xi Jing

▪ Distribution Automation management system in Qing Dao

▪ The 110kV Mengzi Shanghai smart substation

▪ 110kV Beichuan smart substation

Similar co-funding arrangements between the government and the utilities were implemented in South Korea, Japan and Brazil. In all these cases, government support is mainly delivered as a research and development (R&D) subsidy or credit. For example, in Brazil, Federal Law No. 9.991 mandates that 1 percent of each utility’s net revenue must be used for R&D. The Brazilian Electricity Regulatory Agency (ANEEL) mandates sufficient revenue to meet this objective. A significant proportion of this funding is allocated to smart grid initiatives.

The United States both has a highly advanced smart grids strategy and provides a more promising example of public-private cooperation. In 2009, over $4.5 billion was allocated to power grid modernisation under the Recovery Re-Investment Act. As mentioned above, the Department of Energy was provided $3.4 billion to invest through Smart Grid Innovation Grants (SGIGs) to the private sector, with the goal of distribution automation, improving interoperability, collecting smart grid impact data, modernising the grid and improving cybersecurity.

Projects were selected based on a competitive evaluation (not to be confused with competitive bidding). Projects were selected in the order of the highest overall assessment, derived from the metric summarised in the table below.

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Table 5.3: SGIG Merit Review

Source: USDOE

The allocation of public funding involved hands-on monitoring of execution. After selection, projects were required to submit to the Department of Energy detailed plans for project execution, cyber security, metrics and benefits reporting and consumer behaviour studies.

The vast majority of funding was allocated to regulated utilities. SGIG utilities installed over 82,000 smart digital devices to upgrade 6,500 distribution circuits, and deployed a joint $7.9 billion public and own investment in smart grid upgrades, with 27 percent being specifically for distribution automation.

The Department of Energy assessed the program as success, with key results being:

▪ Customer interruption notices and minutes reported reduced by 55 and 53 percent respectively. The network became more resilient to equipment failure and extreme weather.

▪ Utilities reported improvements in average interruption frequency from 17 to 58 percent

▪ Distribution automation avoided over 197,000 truck rolls and 3.4 million vehicle miles travelled.

▪ Savings reduced 2,350 metric tons of CO2.

▪ Significant improvements to Voltage and Reactive Power Management systems ensured system-wide power outages were resolved much faster and the scale of outages was limited significantly. Reactive power requirements were reduced by 10 to 13 percent based on operator’s internal estimates.

In Europe, a number of initiatives are identified where energy regulators support smart grid projects through uplift on the regulated tariffs. The most structured approach appears to be in Italy, where the energy regulator (AEEG) launched a competition-based procedure providing incentives for smart grid pilot projects related to distribution. The incentive guarantees an extra 2 percent return on capital for distribution related network investments over a period of 12 years. To be eligible for the 2 percent additional return on capital, the pilot project must meet specific criteria for cost/benefit assessment of projects.

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Although Italy generally follows incentive-based regulation (where utilities are free to decide how to spend as long as they stay under the revenue cap, and where utilities have an incentive to reduce costs in order to maximise profits), in the cases of smart grids AEEG followed an input-based system of assessment, with a guaranteed return once the approved inputs are implemented. Following the US model, the AEEG developed an input-based system of assessment based on grid technology innovation, new grid services, and grid user participation. The scoring criteria is outlined in the table below:

Table 5.4: AEEG Smart Grid KPIs

A1

SIZ

E

N. generation plants/storage 6

Increase of electricity production injected into the grid 12

Increase of ratio "electricity production / electricity consumption" 8

N. primary substations involved in the project 4

Max A1 30

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INN

OV

AT

ION

Participation of disperse generation to voltage regulation 6

Presence of control system (SCADA) 6

Bidirectional communication and demand response 6

Presence of storage systems and active power modulation 12

Participation of DSO to ancillary service market 10

Max A2 40

A3

FE

ASIB

ILIT

Y Project schedule 4

Quality improvements 6

Max A3 10

A4

RE

PL

ICA

BIL

ITY

% of costs on not regulated subjects (DG and storage) 2

Standard protocols 8

Consistency between investment costs and expected benefits of the project 10

Max A1 20

Max Project 100

To be classified as an appropriate demonstration project, the requirements are that:

▪ Real grid: the demonstration project must be realised in a real existing MV network (1-35 kV) with passive customers and generators.

▪ Active grid: the selected MV network has to be characterized by a reverse power flow (energy flows from MV level to HV level, that is higher than 35 kV) at least for 1% of yearly time.

▪ Automated grid: the selected MV network must be equipped with real time control systems able to automatically record all data needed for the evaluation of the project.

▪ Open communication: non-proprietary communication protocols are required for communication with network active users (generation and storage), to minimize customer costs at the network interface.

Since 2010, AEEG has awarded nine tariff-funded projects on active medium voltage distribution systems to demonstrate at-scale network management and automation solutions necessary to integrate distributed generation. An additional EUR 200 million was provided by the Ministry of Economic Development.

In Romania, the regulator has indirectly promoted smart grid investments by strengthening penalties and rewards for network performance. Most regulators in the European Union (including UK), Australia and New Zealand have penalty arrangements for networks failing to meet their performance targets (typically expressed in terms of system average and customer average interruption minutes). However, such penalties are

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typically minor, and in any case, deviations from performance targets also tend to be minor. In Romania, the regulator is introducing a quality award/penalty factor of +/- 4 percent of allowed revenue.

In response to that incentive, the Romanian state-owned power supply and distribution company Electrica SA partnered with private technology firms Ormazabal and Flashnet to implement a smart grid pilot project in Brasov. The 7-million-euro project aims to incorporate two-way communications and data management on existing power cables to improve the quality of services, reduce network losses and provide functional infrastructure for telemetry systems. Electrica SA reports that the technology when implemented will improve the quality of services by reducing latency of communication, identifying outages and faults within the system pre-emptively and coordinating responses to events in a cost-efficient manner.

A number of initiatives emerging out of the Indian Smart Grid Forum were reviewed. Most of these initiatives consist of technical investments being undertaken by the State-owned utilities, with some subsidies from the National government.

A.2 Enabling Dynamic Integration and Management of Power Sources

The global trend towards variable renewable generation and distributed generation has produced a wide range of responses. While many countries implemented feed-in tariffs for renewable generation, the procedures for technical integration and the rules that must be followed by such generators have often deterred renewable investment. For example, in Indonesia, despite the existence of feed-in tariffs at which PLN (the national vertically integrated utility) “must” buy renewable power, PLN retains freedom to refuse contracts on technical grounds.

In many countries in the LAC region, regulators have started implementing planning guidelines to simplify the procedures that renewable generators must follow to connect to the grid. In both Chile and Mexico, the governments have announced intentions to promote grid integration of renewables through:

▪ Creation of Competitive Renewable Energy Zones (CREZ). The utility will define zones where transmission capacity is available and control systems have been sufficiently upgraded to cope with variable renewables. Developers who locate within specified zones will be automatically connected. This model is based on the approach developed by the Texas regional transmission organisation (RTO)

▪ Requirement for Open Integration Studies. Outside of CREZ, renewable project developers will be provided with transparent list of studies that will be undertaken and standards that must be followed.

In Brazil, where over 45 percent of electricity comes from renewable energy sources, there is already significant experience in the integration of small hydro, wind power and solar. Brazil conducts technology specific procurement auctions based on assessment of grid readiness. Similarly, in China and Vietnam, under respective Renewable Energy Laws and Decrees, power grid operators announce technology specific procurements. In China, the prices for renewable energy purchased from registered energy producers are set by the National Development and Reform Commission (NDRC).

In vertically unbundled markets with competitive generation, the system operator is generally responsible for ensuring stable integration of various power sources through

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competitive procurement of ancillary services. Vertically unbundled markets fall into two categories:

▪ Energy only markets, such as Australia, New Zealand, Singapore and the Philippines

▪ Capacity markets, such as most of the US, Chile and a number of European markets.

In capacity markets, the system operator plans and determines the types of capacity that would be available on the system. In such systems, it is common to observe technical limits on the proportions of variable renewable capacity. By contrast, in energy only markets, the system operator must accommodate any energy that is offered into the system. As result, energy-only markets have been particularly active in incorporating smart grid technologies into their ancillary services.

In the Philippines, the National Grid Corporation is responsible for procuring all ancillary services on long-term contracts. It has entered into a number of contracts with battery storage providers to supply reactive power and voltage regulation in response to greater market penetration by variable renewables. The cost of ancillary services is socialised across all network users through regulated transmission charges.

In 2017, the State Government of South Australia established an AUD150 million Renewable Technology Fund to provide AUD75 million in grants and AUD75 million in loans to eligible energy storage projects. In response to a state-wide blackout due to storms, the Government procured a 100MW battery farm. A consortium including Tesla and Neoen won the procurement to develop the world’s largest lithium-ion battery to be paired with the Hornsdale Windfarm to provide firm power to the state’s electricity grid. The battery can power up to 30,000 homes for a period of an hour in the event of a blackout.

The Australian battery procurement is a variant on one common theme observed in a number of jurisdictions: the emergence of Virtual Power Plants (VPPs). In the VPP model, an energy aggregator gathers a portfolio of smaller generators and/or shedable load and operates them as a unified and flexible resource on the energy market or sells their power as system reserve. While individual components of the VPP may be highly variable and difficult for the grid operator to absorb, the VPP manages variability within its portfolio and presents to the grid the required firm output.

VPPs, in a sense, sit outside the grid but utilise smart grid technologies. VPPs use software and advanced communications to dispatch and coordinated a portfolio of storage sites, variable renewable generators and customer-site demand response control units.

German utility RWE has been operating a VPP since 2012, and has now aggregated the equivalent of 80MW of firm capacity. In addition to variable renewables and storage, this VPP uses biomass generation to smooth power flows. German regulation allows VPPs to bid into the ancillary services market. In many other European jurisdictions and in Australia and New Zealand, current regulations would not yet allow a VPP to be eligible to participate in that market.

South Korea is regarded as a leader in smart grids. For the most part, the Government’s Smart Grid Roadmap 2030 is being internally implemented by the Korean Electrical Power Corporation (KEPCO). The Government has allocated subsidies of around $6.5 billion for technology R&D.

In addition, the Government has led the creation of the the Jeju Island Smart Grid project, which has involved a consortium of 168 companies collectively investing $171 million, with $68.5 million in funding from the Korean Government.

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A key feature of the Jeju Island smart grid project has been the development of standard business models that enable commercialisation of smart grid technologies. VPP has been one of the main models to emerge from this trial.

Based on the lessons learned from the Jeju Island Project, the Korean Government passed the Smart Grid Promotion Act to provide the required regulatory support for the operation of the business models identified on Jeju. The Act established the Smart Grid Promotion Agency to help facilitate coordination of public and private activities in areas where the overall smart grid architecture (including business models) will be rolled out.

Similar city or island-wide integrated projects can be observed elsewhere.

In Japan, the Okinawa Electric Power Company has introduced a demonstration smart grid project to integrate supply of renewable energy on the Okinawa Prefecture’s island of Miyako-Jima (population of 55,000). The project began in 2010, linking the existing power grid to a four MW solar power plant and sodium sulphide battery complex capable of storing four MW of power. In addition, the system manages power from an existing 4.2 MW wind farm. The Okinawa Electric Power Company invested 6.5 billion yen ($75.8 million) in smart grid infrastructure, two-thirds of which was subsidised by the government.

In Spain, the Enel-Endesa Group is a consortium of 11 energy companies and 14 research companies which implemented the Malaga smart-city in Spain from 2009-2013. Broad objectives of the project included testing the deployment of a smart energy management model, implementing and integrating distributed energy resources, and utilising energy storage facilities. The project successfully integrated low-capacity renewable energy resources (wind and solar) with energy efficiency and remote-control kits distributed to households from wind turbines, and solar panels, whose outputs vary based on weather conditions. However, despite the apparent success of the demonstration project, there has been limited comprehensive follow through in other locations in Spain.

A.3 Enabling Shaving of System Peaks

There are broadly two approaches to shaving system peaks: through consumer demand response and through energy storage. Energy storage does not affect demand peaks but flattens the load from the perspective of transmission and distribution grids and electricity generators.

While various energy storage technologies (such as pumped hydro and flywheels) have been around for a long-time as a tool for managing energy reserves, the use of distributed battery storage to limit distribution system peaks as part of the smart grid architecture is in its infancy. The only significant commercial project that was identified is in Australia.

The Australian Government has provided support to regulated utilities to explore use of battery storage to reduce system peaks. An interesting feature of the Australian regulatory regime is that regulated distribution utilities are not allowed to implement battery storage projects in-house. Any storage projects must be ring-fenced from the core operations of the utility and competitively procured. This is because battery storage can provide a wide range of services, including competitive supply of energy. In order to minimise effects on competition, Australia prohibits vertical integration by monopoly distribution and transmission companies into competitive parts of the sector (such as generation and retail).

The Australian Government and Ausgrid (a recently privatised utility in New South Wales) are piloting a AUD100 million initiative across Newcastle, Sydney and the Upper Hunter regions with the goal of testing the benefits of integrating energy storage into network

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management. The program led to the installation of 61 Energy Storage Systems (ESS) to offset grid peaks and reduce requirement for transformer upgrades.

The competitive tender was won by Redflow Energy, which financed and deployed ESS. In Newcastle, Redflow found that peak demand seen by the grid was reduced by 5 to 10 percent due to ESS, with further improvements possible if energy discharge cycles from storage were optimised to households. In the Upper Hunter region, the ESS were found to reduce peak demand significantly, with reductions of up to 43 percent in evening peaks, mostly due to the high ratio of ESS to customers. Overall the program found in the regions a net benefit of up to AUD28 billion over the next 20 years within Australia, providing reliability for consumers as a reduced cost.

On the demand side, another interesting innovation is the integrated management of demand response across numerous customer sites. Under the United States SGIG program, a small proportion of funds was allocated to private companies to provide services to utilities on contractual arrangements that most closely resemble PPPs. An interesting example of that is a project by Honeywell to aggregate and manage automated demand response by large commercial customers. The typical arrangement in the US is for the system operator to contract for demand response directly. Under this project, Honeywell financed (with support from the DOE grant) the roll out of customer site equipment and provided on-going operations with a turnkey service being offered to the system operator.

Apart from the limited number of distributed battery storage trials and integrated demand response business models (including as part of VPP model), the bulk of smart grid implementation around the world has consisted of the roll out of smart meters. Such rollouts have proceeded with various degrees of success.

As mentioned above, a key requirement for the success of smart meter initiatives appears to be ability for the utility to control customer-site appliances remotely, rather than just relying on consumers responding to price incentives.

On a small scale, the Netherlands PowerMatcher trial succeeded in incorporating smart meter technology into smart grid operations. This trial—which involved 42 households in the City of Groningen—was part of the Intelligent Grids Innovation Program, which supported 94 small scale trials of various smart grid technologies through EUR 22.5 million in funding from the Dutch Government. The PowerMatch trial enabled both consumer and supplier control of customer equipment.

On a much larger scale, in Italy, Enel has deployed over 30 million smart meters. The Telegestore system used in these meters allows for time of use and time of year management functions from the consumer end, and active and reactive functions to energy measurement and remote connect and disconnect functions for supply side load control. Supply-side load control functions were able to be activated without customer consent. Enel is reported to have recovered the cost of the initial EUR2.1 billion investment with a five-year payback period and 16 percent IRR through approximately EUR500 million in annual savings.

Most other smart meter programs identified in this study rely on voluntary consumer demand response. While roll-outs have proceeded, there is limited evidence of consumers taking significant advantage of the functionality of such meters.

The government of the United Kingdom has implemented the Smart Meter National Roll-out Programme with the objective of reducing energy consumption by 5-15 percent. Every household is to be offered a smart meter by 2020 through their utility provider. According to numerous studies, most suppliers expect to miss the target of 100 percent

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installation by 2020, or daily installation of 40,000 meters for the duration of the program, and risk incurring potential fines. Currently, only about 8.6 million meters are installed out of the required 50 million, and it is expected that the programme will be extended until 2023.

The costs of the roll out are incorporated into the utilities’ asset bases and recovered through tariffs. A study by the University of Sussex has argued that the program has generated confusion and resistance within households, due to a failure of utilities to engage households on how the technology works, creating risk for the success of the program’s implementation.

In 2014, India announced $4 billion in budget funding for smart metering programs, with an additional $8 billion in funding for loss reduction programs.

Mysuru is the first city in India to have implemented a smart grid project under a formal contract (which has some features of a PPP between the government and a utility) at a cost of roughly $5 million for the initial pilot, increasing to $62 million for the full project. The project is a partnership between Chamundeshwari Electricity Supply Corporation (CESC) and India’s Ministry for Power. The Ministry will fund 50 percent of the investment, with the goal of reaching 24,532 customers, 580 irrigation pump sets, and 504 distribution transformers.

Australia: As highlighted in the Castalia proposal, in 2006 the Victorian Government mandated the compulsory rollout of smart meters (The Advanced Metering Infrastructure Program) to all households and small businesses across Victoria. The goal of the program was to facilitate consumer demand side responses, facilitate competition and reduce peak-demand load within the network through management of power supply. The cost of the roll out was funded by the additional State-mandated charges on the electricity bill (all other distribution utility charges are set by a Federal regulator).

There has been almost no take up of the “smart” features of the meters. According to the Auditor General of Victoria report, the only benefits of the roll out have been in costs avoided for replacement and monitoring of the previous accumulation meters. The Auditor General further concluded that based on market research, two-thirds of Victorians did not understand the benefits of smart meters, and the link between their meter and saving money on their electricity bills. The State Government received criticism for introducing a mandatory program in which it had no control over the costs and which had poorly specified performance requirements. Roughly 13.5 percent of households are paying higher charges for a smart meter that could not be remotely read.

Canada: The government of Ontario, Canada, through the Energy Conservation Responsibility Act in 2006, mandated the installation of 4.8 million smart meters in all Ontario businesses and households by 2010, with costs of about CAD2 billion to be passed on to consumers. Time of use pricing was implemented in 2010.

The program has been severely criticised. Environmental Commissioner of Ontario found a 0.7 percent reduction in peak demand for residential customers over a four-year period. The Ontario Energy Board found that time-of-use pricing did not have success in shifting consumption away from peak periods. The Auditor-General found that the difference in peak and off-peak rates was not sufficient to shift consumption patterns.

Mexico has set itself the ambitious target to roll out over 30.2 million smart meters from 2015-2025. Mexico is the largest consumer of smart grid technology after Brazil in Latin America. Utilising the Pidiregas scheme, which provides public funding to secure private finance, more than two-million smart meters have been tendered through the market under this scheme.

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CFE, the largest utility in the Central America and Caribbean region with more than 35 million customers, is in the process of replacing outdated energy transmission infrastructure and metering equipment with modern technology that enables remote monitoring as well as outage detection. The rollout in CFE's east region was completed in August 2016 and the southeast region was expected to be completed in July 2017.

As part of this roll-out, in 2016 Honeywell was awarded two new regional smart grid projects in Mexico by a consortium appointed by the country's federal electricity company, Comisión Federal de Electricidad (CFE), to manage its smart grid initiatives.

Honeywell will deploy more than 200,000 smart electricity meters along with communications devices and software analytics tools to seven cities in CFE's east and southeast regions. The work will help the utility reduce costs and enhance service by minimizing electricity losses across its transmission network and more quickly identify and respond to power outages.

In France, ERDF is on track to deploy over 28 million smart meters—the Linky—by 2020, with additional utilities set to provide the remaining smart meters, for a combined total of 35 million. The total cost of the Linky smart meter rollout is expected to reach EUR 4.5 billion. The rollout of the Linky meter is expected to facilitate consumers’ ability to monitor and manage their consumption, and receive bills based on their actual consumption. Suppliers in turn will be able to adjust their price offering. ERDF expects the roll out to be partly funded through reductions in meter reader callouts, as well as through an additional surcharge on electricity bills.

The Basque country in Spain has promoted a smart meter, transformation unit and modernized substation roll out under the Bidelek Sareak scheme. The Basque Energy Agency (EVE) financed the initiative, with Iberdrola Distribución Eléctrica, the local electricity utility,a national utility, partnering to supply the technological solutions, and contribute financially. Benefits of the initiative included improved quality and reliability of supply, reduction in costs (as peaks could be better anticipated and managed). In future, the modernization will enable the integration of VRE and DER sources of energy.

Ecuador was the first Latin American country to formalise a national smart meter rollout program. In 2011, Ecuador contracted GE Energy for the rollout of over 25,000 smart meters. The objective of the rollout was to assist with remote connect and disconnect to the grid of customers, efficiency planning and demand side response.

Chinese utilities have issued tenders for 425.8 million smart meters. Annual investment in smart metering was estimated to be $1.4 billion in 2015 and was estimated at $2.9 billion in 2016. In 2020, China is expected to account for over 24 percent of the global smart meter market.

A.4 Integration of Consumer as a Producer

Many countries promote household-level solar generation through net metering, which effectively treats household production as negative load. However, there are few examples of networks accommodating two-way flows.

From 1991, Germany began operationalising two-way flows between consumers and the electricity grid for consumers to sell renewable energy back into the grid through feed-in tariffs. Germany remains the main example of significant two-way flows.

A5. Electric vehicle infrastructure

Denmark has emerged as a leader in the vehicle-to-grid market, with numerous pilot projects underway, including the world’s first commercial vehicle-to-grid project for the

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Danish Utility Frederiksberg Forsyning in partnership with Nissan, Ennel and Nuvve. The Nissan, Ennel, and Nuvve pilot project has been completed, with a total capacity of 10kW available to the network from 10 vehicle-to-grid units. The Danish national grid operator Energinet is examining applying the findings from the pilot project to the national network to better integrate EVs and provide grid stabilisation services. The Parker Project, operating on a slightly larger scale, has a similar objective. It is utilising $2.46 million funding from ForskEL, a national fund to provide grants for technological innovation. The project was expected to run from August 2016 to July 2018 and is being managed by Nissan, Mitsubishi Corporation, Enel and Nuvve.

In the United States, the main trials for the integration of vehicles into the grid are occurring under the Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) Program which aims to make military installations more energy efficient and secure. The program is the result of the partnership between the Department of Defense, Department of Energy and a consortium of research, utility and military institutions. The trial facility at Fort Carson is integrating electric vehicles, generators and solar arrays to supply emergency power. The program is developing specialised software to manage a fleet of electric vehicles which could act as both energy storage devices, provide ancillary services, and a source of power flow correction for the grid. The current trial has incorporated three large EV trucks and two additional heavy EV vehicles into a microgrid and demonstrated their capacity to improve system operation and performance through reactive power injection.

The Toyota City Project in the Aichi Prefecture, Japan will include 3,100 electric vehicles in the city to test grid-to-vehicle and vehicle-to-grid connectivity.

Overall, projects to integrate consumer as a producer tend to be at very early and very small-scale trial stages.

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