Towards 100% renewable energy: Utilities in transition

Cities heading towards 100% renewable energy by controlling their  consumption | Energy Cities

The adoption of the United Nations’ 2030 Agenda for Sustainable Development, and in particular Sustainable Development Goal 7 (SDG7) to ensure access to affordable, reliable, sustainable and modern energy for all, has led to a global consensus around the need to substantially increase the share of renewable energy in the global energy mix. Renewable energy is key to sustainable development and will play a crucial role in advancing progress on various Sustainable Development Goals as well as the global climate objectives set out in the 2015 Paris Agreement under the United Nations Framework Convention on Climate Change (UNFCCC; the Paris Agreement; IEA, IRENA, UNSD, WB, WHO, 2019).

Global status and trends
Building on its first global mapping of 100% renewable energy targets in 2018, the IRENA Coalition for Action, in a joint effort with several partners, has continued to identify and evaluate national and subnational targets. The updated overview of the global status on 100% renewable energy targets includes new targets announced in the past year as well as further details on the type of targets and their legal.

Mapping of 100% renewable energy targets – national level
In 2019, a total of 61 countries had set a 100% renewable energy target2 in at least one end-use sector, up from 60 countries in 2018. Geographically, these 61 countries are distributed as follows: Africa (19), Asia (15), Oceania (10), Central America and the Caribbean (8), Europe (7), and South America (2) (see Figure 1). Of the 61 countries, 14 countries have committed to reaching a 100% renewable energy target in at least one end-use sector by 2030 at the latest, two countries by 2040 and the others by 2050.

Figure 1. Geographical distribution of national 100% renewable energy targets

The mapping of targets shows a high commitment from countries in Africa, Asia and Oceania to achieve 100% renewable energy. Many of these targets were announced through the Marrakech Communique at COP22 (the 22nd Conference of the Parties to the UNFCCC) by countries that are most vulnerable to the effects of climate change, particularly least developed countries and small island states.

In 2019, the one country to revise its renewable energy ambitions to include a 100% renewable energy target was Portugal. The country announced a strategy for achieving 100% renewable electricity generation by 2050 in its Roadmap to Carbon Neutrality, adopted by the Portuguese government in July 2019. The transformation is expected to be achieved through large increases in solar photovoltaic (PV) deployment, building on the existing high shares of wind and hydropower, and coupled with improved energy efficiency to reduce overall electricity consumption.

Targets by sector
While some of the renewable energy targets have been clearly defined in terms of end-use sectors, other targets are broader in scope. In cases where the 100% renewable energy target has not been clearly defined, the category “RE – not specified” has been used in the mapping exercise. Of the countries included in the mapping, 42 fall into this category. In the case of targets that are wellspecified in terms of end-use sector, most are focused on 100% renewable electricity, with few countries having set targets for more than one sector. In fact, the mapping exercise identified 18 targets aiming for 100% renewable electricity. Two countries with a renewable electricity target (Austria and Denmark) have also adopted targets for 100% renewable energy in the transport sector, whereas two (Denmark and Lithuania) have set a target for 100% renewable energy in heating and cooling as well as electricity. Indonesia has thus far announced a 100% renewable energy target in the transport sector. Denmark remains the only country with a 100% renewable energy target that.

Figure 2. Overview of national 100% renewable energy targets, by end-use sector

Type of target/commitment
The degree to which a country’s political leaders and policy makers are held accountable for achieving 100% renewable energy targets depends on the context in which the commitment was made and established. The targets representing the highest level of commitment would usually be those established in national law and are thus legally binding. Other targets may be formally established in policy documents such as nationally adopted energy and climate plans, including the nationally determined contributions(NDCs) under the UNFCCC. Several targets have also taken the form of highlevel policy announcements by national governments or pledges under global initiatives (e.g., the Marrakech Communiqué) but have not been fully integrated into national plans or strategies to date. To provide a comprehensive overview, the mapping in this white paper includes all types of 100% renewable energy targets in its analysis. However, to develop an understanding of the level of commitment, a first attempt has been made in this white paper to distinguish between different target types (see Figure 3).

Figure 3. Overview of national 100% renewable energy targets, by type of commitment

As Figure 3 illustrates, many of the commitments to 100% renewable energy targets were established by Climate Vulnerable Forum (CVF) countries under the Marrakech Communiqué at COP22. The communiqué states, “We strive to meet 100% domestic renewable energy production as rapidly as ossible”. Of the 48 CVF countries, 6 (Costa Rica, Fiji, Papua New Guinea, Samoa, Tuvalu and Vanuatu) have taken additional steps to translate this pledge into their NDCs, most of which are conditional upon receiving appropriate international support and funding. Two non-CVF countries (Guyana and Indonesia) have also included 100% renewable energy targets into their NDCs. Of the remaining 11 countries with 100% renewable energy targets, 10 (Austria, Cabo Verde, Denmark, Djibouti, Iceland, Lithuania, Portugal, Solomon Islands, Spain and Sweden) have defined how they intend to achieve their targets in national energy plans or strategies.

The role of utilities in the energy transformation
Moving from ambitious renewable energy targets to accelerated implementation will require
proactive regulation, new market rules and collaboration between existing as well as new players in the energy market. This is key to making sure that the energy system is fit for renewable energy goals and transitional barriers are removed. In delivering energy to households, businesses and industries, energy utilities have played a crucial role in creating and shaping the current energy system. The ability of utilities to adjust to new demands will partly determine how fast the transformation can happen as well as what their role will be in a future energy system built on very high shares of renewable energy.

Overview of utilities in transition to 100% renewable energy
To further illustrate and understand the role that utilities can play in the transformation to 100% renewable energy, this white paper analyses a selected number of companies operating or having previously operated as “utilities” that are moving towards supplying 100% renewable electricity to their customers, either on their own initiative or because of government policies occurring in the jurisdictions they serve. The case studies cover different geographies, technologies, ownership structures and levels of operation including national, regional and local operations. The case studies were selected by members of the Coalition for Action based on first-hand experience from or familiarity with these utilities and build primarily on first-hand data obtained through interviews with senior representatives of the respective utilities. Table 1 below provides an overview of selected case studies, while detailed case studies are provided.

Table 1. Overview of utility case studies further

National-level utilities

Ørsted is the largest energy company in Denmark, accounting for 50% of electricity generation and 35% of heat generation. Engaged in the generation and distribution of electricity and heat to customers across the entire country, Ørsted develops, constructs and operates onshore and offshore wind farms, bioenergy plants and, to a smaller extent, waste-to-energy plants. In addition to its operations in Denmark, Ørsted is also active as a developer and operator of offshore wind in other parts of the world, with 5.6 gigawatts(GW) in operation in 2019. The Danish government holds a majority stake in Ørsted, owning 50.1% of the company’s shares (Ørsted, 2019a).

In 2018, 75% of Ørsted’s total power and heat generation was achieved through renewable energy sources(41% wind and 34% biomass), an 11 percentage pointsincrease from 2017. The remaining 25% consisted of fossil fuel generation (17% coal and 8% natural gas), as shown in Figure 7.

Figure 7. Ørsted total heat and power generation, 2018

Ørsted has committed to achieving at least 99% renewable energy by 2025 and to fully phasing out coal from its generation mix by 2023 – well before the national target of 100% renewable energy by 2050 (Ørsted, 2017). The target is set to be achieved through substantial increases in offshore and onshore wind deployment, as well as through the conversion of coal- and gas-fired power stations to sustainably sourced biomass.

Regional/state-level utilities
SA Power Networks – South Australia

Since the privatisation of the electricity sector in 1999 there has been no vertically integrated electrical utility in South Australia. Currently there are many electricity generating companies and retailers but only one distributor (SA Power Networks) and one transmission line company (Electranet). SA Power Networks is a privately held monopoly regulated by the Australian Energy Regulator. Its primary role is to maintain and operate the state’s distribution network, which serves around 860 000 homes and businesses and 1.7 million people (SA Power Networks, 2019a).

Figure 8. The changing role of SA Power Networks

South Australia is at the forefront of the Australian energy transformation, with a target of reaching 100% renewable energy in all end uses by 2050 (AEMO, 2018). For the power sector, with currently committed projects in the pipeline, South Australia is expected to reach 73% VRE in electricity generation by 2021 and effectively 100% by 2025/2026. By the end of 2018, about 53% of South Australia’s electricity came from renewables – 35.2% from wind (1 809 megawatts [MW]) and the rest predominantly from rooftop solar (930 MW), with another 135 MW from large-scale solar farms (AEMO, 2018). Natural gas supplied the bulk of the remaining generation with increasingly diminishing supply provided through interconnection with the eastern states. Some emergency local diesel supply also exists. A 500-MW brown coal power station in the state’s north closed in 2016. Prior to that, the majority of South Australia’s electricity generation was from natural gas and brown coal (AEMO, 2018).

Hawaiian Electric Companies – United States

The Hawaiian Electric Companies – Hawaiian Electric (HECO), Maui Electric (MECO) and Hawaii Electric Light (HELCO) – provide electricity services for the majority of the islands that make up the US state of Hawaii (Figure 9). The companies are all investor-owned utilities and together serve 95% of the state’s 1.4 million residents on the islands of Hawaii, Lanai, Maui, Molokai and Oahu (HSEO, 2018). The renewable share of electricity generation reached 26.6% for the three utilities in 2018, up from 23% in 2015.

Figure 9. Overview of electricity providers in Hawaii

Launched in 2008, the Hawaii Clean Energy Initiative (HCEI) was established in Hawaii as a partnership between the State of Hawaii and the US Department of Energy. This initiative’s initial goal was for the state to produce 70% of its electricity from clean and renewable energy by 2030. An RPS of 15% electricity sales by the end of 2015 was also established. The HCEI has since been strengthened and in 2015 the Hawaii State Legislature reinforced the state’s commitment to clean energy by increasing the RPS requirement to 100% renewable electricity by 2045, with interim targets of 30% by 2020, 40% by 2030 and 70% by 2040.

Going from 9.5% renewable electricity generation in 2009 to over 25% in the past decade has required extensive efforts from the utilities, and significant work remains to reach 100% (Figure10).

Figure 10. Hawaiian Electric Companies’ progress towards achieving the 2020 RPS target

The Hawaiian Electric Companies have incorporated renewables in the forms of residential and
commercial rooftop solar, utility-scale solar, battery storage, wind, hydro and geothermal. The
companies’ combined annual oil use for power generation has declined by 88 million gallons
(330 million litres), or about 19%, since 2008, and total carbon emissions have been reduced by about 925 000 metric tonnes between 2010 and 2018 (Hawaiian Electric, 2019b). Recently, contracts have been signed for eight new solar-plus-storage projects for over 275 MW of solar and more than 1 GW of battery storage, all at prices well below the cost of fossil fuel generation (HSEO, 2018). In 2019, the companies issued a second request for proposals seeking about 900 MW of additional renewable electricity capacity.

In 2012, in the aftermath of the Fukushima disaster and Germany’s decision to completely phase out nuclear energy, Stadtwerk Haßfurt set itself the overarching target of achieving 100% locally produced renewable energies by 2030. The immediate response from Stadtwerk Haßfurt was influenced by the town of Haßfurt’s proximity to the Grafenrheinfeld nuclear plant, which was shut down in 2015.

Figure 11. Renewable energy projects implemented (red) and underway (blue), Stadtwerk Haßfurt

The 2030 target is currently planned to be realised across the following sectors: energy generation and distribution, heating and cooling, and industry and sector coupling.

In 2004, the City of Aspen adopted an ambitious goal to supply 100% of the city’s electricity needs from renewable energy resources by 2015. A total of 75% had been achieved by 2014, and by August 2015 the city’s electricity supply from renewables through Aspen Electric was 100% (NREL, 2015). Early in the project, it became clear that some critical definitions and assumptions about the 100% renewable goal needed to be clarified before options could be identified. Although the city had clearly stated a goal of 100% renewable energy, the specific technologies and project types that would be considered eligible as “renewable” energy had not been defined. Clarification was needed about other details that impacted the options available to the city, such as whether the purchase of renewable energy certificates needed to be bundled with an energy purchase. Renewables were determined to include solar, wind, and both small and large hydro. Biomass, landfill gas, sewage gas and directed biogas would be considered on an individual project basis dependent on the conditions of each unique
project. Wind and landfill gas became the primary technologies to complete the 100% renewable energy goal (NREL, 2015). Aspen Electric and the City of Aspen partnered with NREL in developing a pathway towards achieving a 100% renewable electricity supply through a combination of their own hydroelectric facilities and PPAs with wind and landfill gas suppliers. The results of this transformation are shown in Figure 12.

Figure 12. Aspen’s electricity supply transformation, 2014-2015

The city ran into several barriers that related to the different levels of renewables included in
the supply. For example, one barrier came up at around 35% wind energy, which resulted in
an energy imbalance. Thus, to further increase wind energy penetration, the city would have
to buy more wind energy than it actually needed. Around 2014 this barrier was overcome when MEAN agreed to allow Aspen a different method to buy additional wind that eliminated the surplus under most conditions.

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Renewable energy finance: Green bonds

RENEWABLE ENERGY INVESTMENT TRENDS

As renewables have become a compelling investment proposition, global investments in
new renewable power have grown from less than USD 50 billion per year in 2004 to around
USD 300 billion per year in recent years (Frankfurt School-UNEP Centre/BNEF, 2019), exceeding
investments in new fossil fuel power by a factor of three in 2018.

Another defining trend of renewable energy investments has been a geographic shift towards
emerging and developing markets, which have been attracting most of the renewable investments each year since 2015, accounting for 63% of 2018 renewable power investments
(Figure 1). Besides China, which attracted 33% of total global renewable energy investments in 2018, other top emerging markets over the past decade include India, Brazil, Mexico, South Africa and Chile (Frankfurt School-UNEP Centre/BNEF, 2019). Nevertheless, many developing and emerging countries in Africa, the Middle East, South-East Asia and South-East Europe still have a largely untapped renewables investment potential.

Figure 1 Global renewable energy investment (excl. large hydropower), in USD billion, by region, 2004-2018

In addition to the growing technological and geographical diversity, the renewable energy
investment landscape is also witnessing a proliferation of new business models and investment vehicles, which can activate different investors and finance all stages of a renewable asset’s life. Examples include the rise of the green bond market, growing interest in corporate procurement of renewable power and new business models for small-scale renewables such as the pay-as-you-go model.

WHY GREEN BONDS MATTER

Green bonds help bridge the gap between providers of capital and green assets, helping
governments raise finance for projects to meet climate targets and enabling investors to
achieve sustainability objectives. Along with other innovative capital market instruments,
green bonds can support new or existing green projects through access to long-term capital.

A green bond is like a conventional bond in the sense that they both help the bond issuer to raise funds for specific projects or ongoing business needs in return for a fixed periodic interest payment and a full repayment of the principal at maturity. A green bond differs in the “green” label, which tells investors that the funds raised will be used to finance environmentally beneficial projects. The green bond market started about a decade ago and has undergone rapid growth in the past five years (2014-2018), as global efforts to scale up finance for environmentally beneficial assets intensified. From a market dominated by development banks,
green bonds have experienced not only growth in the total amount issued, but also a diversification of issuer types and sectors financed, and a widening geographic spread.

The green bond market continues to offer enormous growth potential. The cumulative
issuances of green bonds are below USD 1 trillion, while the global bond market is valued at around USD 100 trillion. On an annual basis, green bonds raised USD 167 billion in 2018, while the total bond market raised around USD 21 trillion (CBI, 2019a; SIFMA, 2019), as seen in Figure 2.

Figure 2 Green bond issuances, renewable energy power investment, renewable energy power investment need,
low-carbon energy transformation investment need and global bond issuances (USD, annual)

MARKET OVERVIEW

The green bond market has taken off in the past five years, with 2019 issuances expected to reach USD 190 billion. Along with the growing amount of capital raised, the market also expanded in its geographic reach, diversification of issuers and currencies in which green bonds are offered. Renewable energy leads the use-of-proceeds categories and is present in around half of all green bonds issued.

Overall, annual global green bond issuances rose from EUR 600 million in 2007 to USD 37 billion in 2014 and USD 167 billion in 2018 (Figure 3) (CBI, 2019a). For 2019, a new high of USD 190 billion is expected (CBI, 2019b).

Figure 3 Annual green bond issuances, per region, 2014-2018, USD billion

Green bonds are also issued in more currencies than ever before. While the US dollar and the euro are the top two currencies of issuances (accounting for 83% of issuances, by number, in 2018, followed by the Chinese renminbi), green bonds were issued in a record 30 currencies in 2018 (CBI, 2019a).

Renewable energy dominates green bond issuances, followed by energy efficiency projects
and clean transport. Most green bonds finance multiple “green” categories (Figure 5). Out of the sample of over 4 300 green bonds analysed by IRENA, 50% of the bonds (by volume, in USD) had renewable energy as one of the use-of-proceeds categories, while 16% were solely earmarked for renewable energy assets. On a regional basis, 21% of green bonds in Europe were dedicated only to renewables (by volume, in USD), 19% in Africa, 16% in the Americas and 14% of green bonds in AsiaPacific (IRENA, forthcoming (a)).

Figure 5 Breakdown of green bond issuances by use of proceeds, by cumulative volume (USD), 2010-2019*

OPPORTUNITIES FOR ENGAGEMENT

While the promise and potential of the green bond market is large, scaling up current issuance
levels will require co-ordinated actions from multiple stakeholders to reduce market barriers.
Those barriers include lack of awareness of the benefits of green bonds and hence a lack of local investor demand, lack of clarity regarding green bond guidelines and standards, a shortage of green projects and high transaction costs for green bonds compared to traditional bonds.

KEY GREEN BOND STANDARDS

Green Bond Principles (GBP): Core components

Use of proceeds: Bond proceeds should be described in the bond offering documentation,
with projects’ environmental benefits described and, if possible, quantified. Share of financing
versus re-financing amounts should also be provided by the issuer. The GBP list the most
commonly used types of projects supported by or expected to be supported by the green bond market. These are:

  1. Renewable energy (production, transmission, appliances and products);
  2. Energy efficiency (e.g., new/refurbished buildings, energy storage, district heating, smart grids and products);
  3. Pollution prevention and control (e.g., reduction of emissions, waste prevention/ reduction);
  4. Environmentally sustainable management
    of living natural resources and land use (e.g., sustainable agriculture, fishery, aquaculture and forestry, natural resources preservation or restoration);
  5. Terrestrial and aquatic biodiversity conservation (protection of coastal, marine and watershed environment);
  6. Clean transport (e.g., electric, hybrid, public, rail transport or infrastructure, reduction of emissions);
  7. Sustainable water and wastewater management (e.g., sustainable water infrastructure, wastewater treatment, drainage systems, flood mitigation);
  8. Eco-efficient and/or circular economy adapted products/technologies (e.g., sustainable products, resource-efficient packaging and distribution);
  9. Green buildings meeting applicable standards or certifications.
Climate Bonds Standard (CBS): Categories of eligible projects

Bonds could facilitate vast global capital flows into low-carbon assets. Through co-ordinated action between policy makers and the financial sector, green bonds can mobilise the large capital pools owned by institutional investors.

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Electricity Storage Valuation Framework

Electricity storage refers to technologies that store electrical energy and release it on demand when it is most needed. The storage process often involves conversion of electricity to other forms of energy and back again.2 With its unique ability to absorb, store and then reinject electricity, electricity storage3 is seen as a key solution for addressing the technical challenges associated with renewables integration alongside other solutions (e.g. more flexible demand, accelerated ramping of traditional power plants). Consequently, storage is garnering increasing
interest in the power sector and is expected to play a key role in the next stages of the energy transition.

Based on recent analysis by the International Renewable Energy Agency the renewable share of global power generation is expected to grow from 25% today to 86% in 2050. The growth is especially strong for VRE technologies – mainly solar photovoltaic (PV) and wind power – with an increase from 4.5% of power generation in 2015 to around 60% in 2050. Furthermore, almost half of PV deployment could be achieved in a distributed manner in the residential and commercial sectors, in both urban and rural locations (Figure 1).

Figure 1: Electricity generation mix and power generation installed capacity by fuel, REmap case, 2016–50

The role of electricity storage in VRE integration
Since the first quarter of the 20th century electricity storage, mainly in the form of pumped hydro, has been used to provide a wide range of grid services that support the economic, resilient and reliable operation of power systems. The great majority of global electricity storage capacity deployed up to the present day is pumped hydro due to its favourable technical and economic characteristics (IRENA, 2017a). Over the last hundred years, the electricity storage industry has continued to evolve and adapt to changing energy and operational requirements and advances in technology.

The services that electricity storage can provide depend on the point of interconnection in the power system. For example, when connected to the grid at the transmission level, electricity storage can support increasing shares of VRE (as explained above), participate in electricity market bidding to buy and sell electricity, and provide ancillary services at the various timescales relevant to technical capabilities of each technology. When connected at the distribution level, electricity storage can provide all of the above services and in addition can be used to provide power quality and reliability services at the local substation, defer distribution capacity investment, and support integration of distributed renewable energy. It can also be connected to other generation facilities, allowing for higher price capture, provision of grid services and at the same time savings on connection costs. Finally, electricity storage can be placed behind the meter (Figure 5) to support a customer in increasing PV selfconsumption, thereby reducing electricity bills (where time-of-use demand-side management schemes exist), improving power quality and reliability, and potentially
enabling participation in energy management, wholesale and ancillary services markets through aggregators.

Figure 5: Grid applications of energy storage

Physical location and operational mode (coupled with generators or standalone), along with the regulatory environment and market structure under which electricity storage operates, greatly affect the type of analysis needed to estimate both system-wide and project-wide
benefits of electricity storage. These considerations are explained in more detail in Phase 3. For example, electricity storage can be operated as a standalone unit or co-located with generation facilities, e.g. solar PV and wind farms. In the case that storage is co-located with
a PV farm, rather than being a standalone unit it is an asset of a “hybrid power plant.

Utilising the system-marginal prices from Phase 3, the various services a storage project can provide can be optimised to maximise the revenue the project receives. As a result of the optimisation, the hour-to-hour (or intra-hour) dispatch of the electricity storage project and
stacking of its various revenue streams can be visualised. Figure 7 shows the type of output from storage service stacking that can be expected from Phase 4. In this illustration, the entire capacity of a 6 megawatt-hour (MWh) electricity storage facility is used to shift VRE from hours 11–14 to hours 18–21.

Figure 7: Illustrative output from Phase 4

Figure 8 shows an example of the outcome from a project feasibility model. In this particular example, although the system benefits outweigh the costs, the monetisable benefits are less than the costs, making the project economically infeasible for the project owner. The difference between the cost and the monetisable benefit, or the economic viability gap, if greater than zero, could be due to high storage capital costs or unfavourable market mechanisms.

Figure 8: Illustrative output from Phase 5

Using power system models to assess value and viability

Figure 9: ESVF phases and the types of models used

In these cost-effective cases, a variety of regulatory options should be considered to ensure that costeffective projects are deployed. Policy makers and regulators can then use the results of this analysis to identify the economic viability gap and devise appropriate incentives so that projects that are seen to be worthwhile at the system level are sufficiently compensated at the project level to move forward. This is particularly relevant in the case of a liberalised market.

The weighted average competitive scores for each technology and for each case are calculated by multiplying the competitive scores, weighting and suitability matrices in Steps 1 to 3. Technologies are then ranked based on their weighted average score for a given case, with 1
being the most suitable for a specific application, 10 the least suitable. Rankings can be shown as a heat map of how suitable each technology is for each case (see Figure 17 and Figure 18). A green colour denotes most suitable technologies while red shows less suitable ones. The topranked technologies are used in the subsequent project feasibility analysis phase of the ESVF. Please note that values in this section are purely indicative, and they have to be adjusted case by case when performing the analysis depending on the system, the technologies and other specific conditions.

Marginal peaking plant cost savings Power systems are designed with enough firm capacity
to accommodate expected demand under both normal operations and contingencies. In a grid system with a growing load, the corresponding increasing peak is usually fulfilled by building new peaker capacity, the generation resources that are only utilised during peak hours. In systems with increasing proportions of VRE, peaks in the net load become higher and narrower, reducing the operating hours for peaker plants and making a business case for electricity storage with limited capacity to replace peaker plants cost-effectively. Electricity storage can potentially provide firm capacity to the system, deferring the need for new peaker plants.

Figure 24: Illustrative output from a price-taker storage dispatch model

With the energy and reserve prices from the system value analysis, and the optimal dispatch results from the pricetaker storage dispatch model, the revenue of the storage project can be calculated. Based on the application ranking from the storage technology mappings – stating
which technologies are most appropriate for the case – the cost side of the analysis can be determined, including CAPEX, OPEX, depreciation and taxes. The cash flow, as well as the net present value (NPV) and internal rate of return (IRR) for the project can be calculated (Figure 25).

Figure 25: Example of electricity storage project financial statements

Using power system models to assess value and viability As the proportion of VRE in power systems increases, electricity storage is becoming recognised by stakeholders as an important tool for effective VRE integration. Several examples of how electricity storage can facilitate VRE
integration are discussed in the next part of this report (Part 3), showing how early business cases are already driving deployment of storage in some jurisdictions. Depending on the primary service the electricity storage provides, however, other technologies may be capable
of meeting the same need. The cost-effectiveness of electricity storage must therefore be assessed at system level and compared against other technologies. Past research has demonstrated that stacking revenues from the variety of services that electricity storage can
provide is key to accurately accounting for the benefits of electricity storage, as well as a necessary condition for its commercial viability. The ESVF described in this report puts emphasis on the benefits (including revenue streams) electricity storage can bring both to its owners and, more importantly, to the power system.

Real-world cases of storage use in power systems

Renewable energy has advanced rapidly in recent years, driven by innovation, increased competitiveness and policy support. This has led to the increased deployment of renewable energy technologies worldwide, with their share of annual global power generation rising from 25% today to 86% in 2050 under the International Renewable Energy Agency (IRENA) Paris compliant REmap scenario In the same year about 60% of total generation comes from variable renewable energy (VRE), mainly solar photovoltaic (PV) and wind, which are characterised by variability and uncertainty.

Electricity storage systems have the potential to be a key technology for the integration of VRE due to their capability to quickly absorb, store and then reinject electricity to the grid. Because of this, electricity storage is gaining an increasing interest among stakeholders in the power sector. Policy makers therefore need to understand the value of these resources from a technology-neutral perspective. The IRENA Electricity Storage Valuation Framework (ESVF) aims to guide the development of effective electricity storage policies for the integration of
VRE generation. The ESVF shows how to value storage in the integration of variable renewable power generation. This is shown in Figure 28.

Figure 28: Electricity storage valuation framework: How to value storage alongside VRE integration

When the share of variable renewable energy (VRE) in the system is low, operating reserve requirements have traditionally been defined as a percentage of the load or as the largest contingency of the system, or in other words, the largest generating unit at that time. With this
low VRE penetration, reserves have been divided into FCR or primary reserves, FRR or secondary reserves and RR or tertiary reserves. FCR is used to stop the frequency deviation and needs to act within the first seconds after the contingency, FRR restores the frequency to its
nominal value and acts within 30 seconds and RR is used to replace the FRR and acts within 15 minutes.

In this regard, the United Kingdom system operator, National Grid, developed the EFR product, which it defines as a dynamic service where the active power changes proportionally in response to changes in system frequency. The EFR service was created specifically for energy storage and requires a response within 1 second once the frequency has crossed a threshold, which can be either ±0.05 hertz (Hz) (service 1, wide-band) or ±0.015 Hz (service 2, narrow-band). In Figure 30 the EFR service is positioned with respect to the other frequency response services in the United Kingdom.

Figure 30: Frequency response services in the United Kingdom

Besides the EFR product, which is already implemented and being used in daily system operation in the United Kingdom, there are other examples of power systems with similar
products that, although not implemented yet, will encourage the participation of energy storage in reserve provision. For example, the Australian Energy Market Operator (AEMO)
has developed an FFR product. AEMO refers to it as “the delivery of a rapid active power increase or decrease by generation or load in a timeframe of two seconds or less, to correct a supply–demand imbalance and assist in managing power system frequency.

Figure 34: South Australian total regulation FCAS payments

As for the value, batteries are proven to have lowered the cost of FCAS in South Australia, as shown in Figure 34. Data show that during the end of 2016 and in 2017 payments to
existing fossil fuel generators were very high, being over AUD 7 million in some six-week periods. With the installation of the Hornsdale project, this service can be provided in a
cheaper way. In 2018 the total savings in the FCAS market are estimated at AUD 40 million.

Figure 37: Net load curve (duck curve) for the California power system, 15 May 2018

The duck curve is already prominent in California, where it first appeared. But it has also been observed in other parts of the United States, such as in the New England states (Roselund, 2018). To manage this net load curve, the grid operator needs a resource mix that can react quickly to adjust production and meet the sharp changes in net demand. In California the first ramp in an upward direction occurs in the morning, starting around 4 am.

Figure 58 shows the solar PV share in a least-cost minigrid in 2017 and in 2030, considering two types of Liion batteries (nickel manganese cobalt [NMC] and nickel cobalt aluminium [NCA]). The graph has been prepared using results from energy modelling software (HOMER Pro) and input data from IRENA’s latest cost report on storage (IRENA, 2017a). It shows that, in 2017, development projects with a 2.5% nominal discount rate had an optimal solar PV share of about 90% with either NCA or NMC batteries. Commercial projects in a low-risk context (10% weighted average cost of capital [WACC]) had renewable share values of 44.5% with NCA and 50.7% with NMC. The results for the optimal PV share in mini-grids in a riskier context (15% WACC), typical of offgrid locations, showed a renewable fraction of only 36% using NCA and 38% using NMC batteries.

Figure 58: Solar PV share in least-cost hybrid mini-grids

Storage deployment in an off-grid context There has been a rapidly increasing interest in deploying storage solutions in off-grid contexts, especially in minigrids that are located in rural areas where there is no access to the electrical grid or on islands that rely on expensive and polluting diesel generation. This has been driven by the need to accommodate increasing amounts of solar PV, and to a lesser extent wind, to provide electricity access or displace diesel generation.

The role of aggregators and the value they can provide to BTM storage should be noted. Aggregators are new market participants that operate a virtual power plant, which is an aggregation of dispersed distributed energy resources with the aim of enabling these small energy sources to provide services to the grid. Figure 63 is an overview of how an aggregator works.

Figure 63: Overview of an aggregator

Aggregators allow enhanced participation of BTM storage in the different electricity markets, help decrease the marginal cost of power and optimise investment in power system infrastructure; however, they require a proper regulatory framework and advance metering
infrastructure in order to exploit their full potential.

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Employment Potential of Emerging Renewable Energy Technologies

Floating solar photovoltaic (FPV) technology offers a new and additional pathway to realize India’s clean energy ambitions. It taps the country’s large water reservoirs to overcome some of the persisting issues of ground-mounted solar, such as the lack of levelled land, evacuation infrastructure and performance degradation due to high operating temperatures. Concurrently, FPV provides additional employment opportunities. The Council on Energy, Environment and Water (CEEW), the Natural Resources Defense Council (NRDC), and the Skill Council for Green Jobs (SCGJ) have undertaken periodical studies to estimate the direct jobs created in the solar and wind industry since 2014. In this study, we estimate the direct employment potential across the project deployment cycle in the FPV sector. This estimate is drawn from project-based case-studies generated through surveys and interviews with manufacturers, developers, and EPC (engineering, procurement, and construction) providers. We also provide an insight into the operational strategies and team structure in addition to discussing the typical duration of different phases of project development and the corresponding workforce employed.

KEY FINDINGS

• A small-scale FPV plant (capacity <1 MW) directly employs 58 workers while a mid-scale (capacity <10 MW) plant 45, over the course of their deployment.

• The FPV sector generates indirect job opportunities through manufacturers of specialized components like floats, anchors, and mooring system as well as domestic module manufacturers.

• The FPV sector offers opportunities for people qualified in hydraulic engineering, marine
architecture, and plastic blow-moulding techniques, some of the key skills required for bringing an FPV plant to life, in addition to those required in groundmounted solar operations.

• By setting time-based targets for FPV capacity, the government could widen the employment potential of this sector, which would bolster efforts to drive India’s COVID-19 economic recovery and achieve its Paris Agreement goals.

Table ES1 Overview of Operations in Deploying a Floating Solar
Photovoltaic Plant of Different Capacities

Employment Insights from the Development of a Mid-Scale Plant

Figure ES1 Time-Share (days) of Project Development Cycle
Phases for a Mid-Scale FPV Plant

Floating photovoltaic (FPV) solar is an emerging technology in which solar photovoltaic (PV) modules are installed (floated) on a water body. Asia has taken a lead in FPV solar deployments, driven by rapid capacity deployments in China, India, South Korea, Taiwan,
Thailand, and Vietnam, and is expected to host two-third of the global capacity. FPV’s global installed capacity was 2.6 GW by August 2020 and a study projects a 20 percent annual growth till 2025.1 A conservative estimate puts the global FPV potential at 400 GW, which indicates enormous opportunities for this sector’s growth.

For clean energy transition, FPV technology offers immense opportunities for India, as water bodies are spread across its vast landscape. By the middle of 2019, India had about 2.7 MW of installed FPV capacity and projects with a combined capacity of 1.5 GW capacity are under development.3 The Government of India has set a target of achieving 10 GW of FPV capacity by 2022.4 According to someestimates, India can build 280 GW of FPV capacity by by utilizing about 30 percent area (nearly 1,800 square kilometres) of its medium and large water reservoirs.5 The bid prices for FPV tenders are also steadily declining, registering a 45 percent drop in prices between 2016 and 2018. As a result, India has achieved the lowest cost for FPV projects at `35 ($0.5)/watt, which was offered during the bid for 70 MW FPV capacity in Kerala.

OPPORTUNITIES FOR FPV IN INDIA
FPV offers a promising option for supporting India’s clean energy transition. FPVs face fewer challenges compared to ground-mounted solar plants which are often confronted with issues such as unavailability of levelled land for installation, lack of power evacuation infrastructure in proximity to the installation site, and performance losses due to high operating temperatures. FPV eliminates the need for land by exploiting the existing artificial and natural water bodies like reservoirs and lakes. When these water bodies are in close proximity to an electricity generation site (e.g. hydropower dams or thermal power plants), an easy access to the transmission network is assured. The efficiency of solar generation is also enhanced by cooling effect of the water beneath and reduced soiling of the module surface.

Overview of floating solar technology

An FPV system consists of PV modules mounted on a floating structure, supported by mooring lines and anchors embedded in the water bed. The floating structure consists of a float, commonly made of high-density polyethylene (HDPE), designed to withstand water currents, local wind, and weight of the PV modules and auxiliaries. The floats are occasionally made of fibrereinforced plastic (FRP) and metals. Cables connect the modules to the inverters, which are typically installed at the shore. Figure 1 shows a schematic representation of a typical FPV system with its main elements.

Figure 1 Schematic Representation of Different Components of an FPV Plant

METHODOLOGY
As FPV is a sunrise sector of the economy, we use a project-based analysis to assess the employment potential in the sector. We derived insights about operation strategies, organisational structure, and employed workforce at a project level through surveys and interviews with manufacturers, developers, and engineering, procurement, and construction (EPC) providers.

KEY FINDINGS AND DISCUSSION
We provide insights from the survey responses and telephonic discussions in this section. We have gathered details on the average duration of activities and number of people employed along with how the duration of activities and workforce employed change based on the project size and company profile. These are indicative numbers based on the limited responses. A more comprehensive study undertaken when the sector matures would provide a clear picture of overall employment created over the course of an FPV project.

Figure 2 An FPV Solar Project Traverses Four Stages for a Successful Deployment

OPERATION AND MAINTENANCE
Operation and maintenance (O&M) of FPV plants are relatively smoother than ground-mounted solar. This is because installations on water do not give rise to issues like
accumulation of dust and/or sand, common in groundmounted installations. Therefore, periodic maintenance, which includes activities such as module cleaning and site cleaning, is done only four times a year for a small-scale plant and 28 times a year for a mid-scale plant.

Overview of Operations in Deploying a Floating Solar
Photovoltaic Plant of Different Capacities

We are upbeat about the sector’s potential to grow, and our respondents foresee an increase in employee strength in the coming three years. An interesting observation from our case-study is the possibility of additional employment prospects for local boatmen in project sites. Since the FPV project is primarily accessed by a boat, for carrying out installation and maintenance activities, the developers and EPCs can outsource these services to the local community living close to the water body. Although the number of jobs created would be small, it surely opens up an additional source of livelihood.

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How India’s Solar and Wind Policies Enabled its Energy Transition

Trading Coal Plants for Solar Farms in India | NRDC

In 2015, India announced ambitious targets for renewable energy—175 GW by 2022—one
of the largest expansion initiatives in the world. Just four years later, at the United enewable energy (RE) capacity to 450 GW by 2030 (PIB 2019). India’s journey to reaching these targets is at a critical juncture. The pace of capacity addition in utility-scale wind and solar power, which saw a rapid increase during 2014–2017, has since slowed down (Figure ES1).

Figure ES1
Pace of capacity
addition in wind and
solar projects has
slowed down

Private investment has shaped deployment trajectories so far. Today, solar and wind technologies have advanced, supply chains have strengthened, and expertise has developed.
Despite the highs and lows, investor confidence in India’s RE sector continues to remain robust. Further, many factors favour investments in RE. It has proved itself to be resilient in
times of crisis, including the COVID-19 induced shocks in 2020. There are strong signals
that RE is a preferred choice, not just because of its green attributes, but because of its
favourable cost economics for all stakeholders.

Central policies: kickstarting solar but leaving wind behind
The initial drivers for RE capacity addition were fiscal, financial, and tax incentives, like
accelerated depreciation, generation-based incentives, and feed-in tariffs (FiTs) determined
by state commissions. Wind turbine manufacturers were the first movers. The de-licensing of
generation under the Electricity Act 2003 (EA) set the stage for private investments in RE.

Currently, apart from setting up inter-state projects, there are no other mechanisms to equitably share the costs of hosting RE projects to supply power to other states. Further, despite RE tariffs attaining grid parity, investors continue to rely on RPOs for demand creation, indicating deeper causes obstructing further RE penetration in markets. Inadequate compliance of Central policies by states also point to certain legitimate state concerns that may not have been addressed (Figure ES2).

Figure ES2
State concerns that
remain unaddressed
in Central policies till
2014 and beyond
Source: Authors’ analysis

Private investment has shaped deployment trajectories so far. Today, solar and wind technologies have advanced, supply chains have strengthened, and expertise has developed. Despite the highs and lows, investor confidence in India’s RE sector continues to remain robust. Further, many factors favour investments in RE. It has proved itself to be resilient in
times of crisis, including the COVID-19 induced shocks in 2020. There are strong signals that RE is a preferred choice, not just because of its green attributes, but because of its favourable cost economics for all stakeholders.

From approximately 21 GW of utility-scale solar and wind capacity at the end of financial year (FY) 2012 (1 GW solar and 20 GW wind), India achieved 70 GW capacity by 31 September 2020 (32 GW ground-mounted solar and 38 GW wind) (MNRE 2020b). This growth story is undoubtedly remarkable. Solar and wind energy have also proved to be resilient in times of crisis, including during the COVID-19 pandemic in 2020, and have continued to attract investment and attention from policymakers.

Figure 1
The rate of growth
in solar and wind
capacity addition
is slowing down
(2008–2020)

Before we embark on a policy analysis to determine the best tools to address the above challenges, we look back and study the sector’s evolution and evaluate the policies’ impact
on RE. As RE growth slows and faces newer challenges, it is the right time to conduct such
an analysis. Such an exercise will enable us to understand what are the gaps in the existing
policies that need to be mended to adapt to the changing dynamics and yet achieve our
objectives. The legislative architecture, along with a diversity of stakeholders and their objectives and interests, makes power sector policymaking and governance a complex space.
Therefore, policy evaluation can be done through multiple lenses. This study focuses on
the evolving risks for project developers in the bulk RE procurement market and the policy
response of the Centre and states to those risks.

Solar Park Scheme
Land procurement in India is hugely complicated, with challenges ranging from the legal to the political (TERI 2017). For developers, private procurement is expensive and timeconsuming. This is evidenced by the consecutively increasing time limit for obtaining possession under the NSM. In Phase I, 180 days was the time limit; in Phase II, Batch I, the time limit was increased to 210 days; and currently, developers must show possession only at the time of commissioning the project.

The pace of solar
park development
under the Central
scheme has been
slow (as on 31
December 2019)

Renewable purchase obligations – a regulatory mechanism for creating demand

The NSM, Solar Park Policy, and other fiscal incentives are supply-side measures, targeted
at reducing investment risks. However, a measure to create demand was essential because
RE was considerably more expensive than conventional power in 2010. Demand for RE was
created through the RPO mechanism.

Setting RPO targets
The RPO targets notified by states are set out in Table A1 in the Annexure. As is evident,
states’ RE ambition varies widely, and there was considerable variance between them and
the NAPCC targets. Karnataka, Tamil Nadu, Maharashtra, and Rajasthan set relatively high
targets, while Andhra Pradesh, Bihar, Madhya Pradesh, and Uttar Pradesh set quite low
targets.

Compliance with RPO
The obligated entities can comply with their RPOs through two routes: direct procurement (FiT/competitive bidding) and purchasing RECs from power exchanges. State regulations typically contain provisions for monitoring compliance, which require the obligated entities to submit information to the state nodal agencies, and the nodal agencies are required to file periodic compliance reports with the SERC. The SERC can also initiate suo moto proceedings to verify compliance.

Variance in compliance within states
The MNRE has consistently been urging states to align their RPO trajectories with that of
the Central Government and ensure strict compliance. In August 2019, the MNRE sought
APTEL’s intervention to nudge SERCs to enforce and align RPOs and not to allow any waivers
or carrying forward (MoP 2020a). In 2019–20, some RE-rich states, including Maharashtra,
Gujarat, Tamil Nadu, Rajasthan, and Telangana, fell short of meeting their RPO targets.
Apart from Andhra Pradesh, Rajasthan, Karnataka, and, more recently, Tamil Nadu, no
other state has met their RPO targets (MoP 2020a). Figure 4 compares the RPO compliance
situation across 2015–16 and 2017–18 of Tamil Nadu, Maharashtra, Bihar, and Punjab and is
representative of the compliance situation across the country.

Figure 4
Compliance with
RPOs is uneven
among states and
discoms

Participation in the REC market mechanism
The trading mechanism instituted for RECs in the power exchanges has not led to its uptake,
as there has been a consistently high number of unredeemed RECs (see Figure 5). In addition,
developers installed only around 2266 MW of RE capacity in 2010–2017 under the REC
mechanism.

Figure 5
RECs consistently
remain unsold in the
market

Policy evolution in RE-rich states

The southern and western states of India have a long history of RE development since RE
resources are concentrated in these states (Figure 7). These states attracted investments in
solar and wind energy well before the launch of NAPCC and the NSM. This section recounts
the journey of RE policies in states that have high solar and wind energy potential. The RErich states covered are Andhra Pradesh, Gujarat, Karnataka, Madhya Pradesh, Maharashtra,
Rajasthan, Tamil Nadu, and Telangana.

Figure 7
RE resource potential
is concentrated in
western and southern
India

Policies pre-2014
In January 2009, Gujarat became the first Indian state to launch a solar power policy (Economic Times 2010). In 2012–13, over 40 per cent of Tamil Nadu’s total capacity was based on wind power (TN Energy Department 2012), well before the Government of India adopted the ambitious target of 175 GW RE capacity by 2022, including 60 GW wind.

Global market developments
Apart from reduced risk perceptions due to stronger institutional mechanisms, developers’
expectation of fall in solar module prices also drove them to place extremely aggressive bids
in the auctions (Deign 2017). Solar module prices witnessed an overall drop in prices (see
Figure 9). However, even small fluctuations in module prices can affect project economics
adversely.

Figure 9
Average module
(multicrystalline)
prices have declined
(2011–2019)

There were short periods when module prices increased during 2017–2020 due to various
reasons such as China slashing its subsidies, reduced polysilicon supply in China, module
suppliers demanding price renegotiation, and supply chain disruptions due to the COVID-19
pandemic (Bridge to India 2017). Excessive reliance on imported modules and largely from a
single country, makes the projects vulnerable to geopolitics and domestic policies intended to
promote domestic manufacturing (Chawla 2020).

2016 onward, SECI’s tendering activity has shifted towards ISTS-connected solar projects.
Between 2016 to 2019, it issued tenders worth 13,000 MW of solar PV capacity (ISTS I to ISTS IX) and 12,600 MW of wind capacity (Tranche I to Tranche IX). Figure 12 shows the deployment progress of solar projects awarded under the ISTS I to ISTS IX tenders by the SECI (as of August 2020).

Figure 12
ISTS-connected solar
PV projects have
poor completion
record

Policy evolution in RE-deficit states

As discussed above, southern and western states in India have abundant RE and land resources to develop large-scale wind and solar power projects. However, the northern states in the Indo-Gangetic plains are densely populated, agricultural states. The mountain regions in the north have excellent solar resources and are sparsely populated but have forest areas and difficult terrains and low transmission capacities. The coal economy is dominant in the eastern states.

Looking back to look ahead

With the evolving policy landscape at the Central and state level, we have seen India’s renewable energy sector grow tremendously. In 2010, the total installed RE capacity was just about 18 GW, which has grown almost five-fold over the decade. As our analysis suggests, there were high and low points in this journey. Every time a roadblock emerged, India has been successful in testing and identifying alternate approaches and solutions. Some of these include bundling solar power with conventional power to counter high tariffs in 2010; introducing solar parks when deployment became slow and tough; increasing RPO targets to create the necessary demand; creating and backing SECI to address counterparty risks; accelerating tendering activity to signal a commitment to creating strong pipelines; encouraging solar–wind hybrid parks to improve utilisation factors; introducing protocols and mechanisms such as market-based economic dispatch, a real-time market, and a green term ahead market to optimise grid integration costs. With economics favouring RE, its share in India’s electricity mix is only expected to grow.

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The Future of Distributed Renewable Energy in India

The Future of Distributed Renewable Energy in India - CPI

India is the world’s third largest carbon emitter, with emissions expected to rise as the economy grows. While this economic growth is important for advancing development objectives, especially in the wake of a likely recession due to the COVID-19 pandemic, it
also poses a challenge as around 600 million people in India are at risk from the impacts of
climate change such as floods, wildfires, and heat waves. Additionally, inaction on this threat
could shave USD 1.12 trillion off the country’s GDP by 2050,2 eroding progress on sustainable
development and poverty alleviation in a country that already struggles with meeting basic
needs.

India has set ambitious targets to increase the share of renewable energy (RE) in its energy mix. The Government of India (GoI) plans to install 175 GW of renewable energy projects by 2022 and 450 GW by 2030. To put that in perspective, total installed energy capacity in India at the end of 2020 was 379 GW, or which 93 GW (25%) was RE. To date, the government’s primary focus of RE expansion has been on large grid-scale solar. However, achieving India’s ambitious RE targets will also require an increase in distributed renewable energy (DRE) projects. If a more favorable regulatory and policy environment is created, such DRE projects, though smaller in size, have greater scalability potential. They also avoid the long lead times and execution bottlenecks associated with public-sector offtake procurement projects.

Figure ES1: DRE annual financing market

Backed by central government incentives, states had initially created a favorable policy environment for DRE. However, in recent years, a number of these incentives have been rolled back. For example, due to RTS subsidy rollbacks, state electricity distribution companies (DISCOMs) are turning hostile towards RTS as they foresee a loss in revenue, an increase in costs, and the longer-term threat of disintermediation. In addition, the COVID-19 outbreak has had a severe financial impact on all stakeholders, leading to a conservative outlook on demand, profitability, and cash flows.

POLICY GAPS AND OPPORTUNITIES

In addition to its current focus on large grid-scale projects, to meet its sustainable energy goals India needs a shift in policy focus towards creating a robust private market for the DRE sector.
A stable policy environment with incentives for all stakeholders is required to accelerate
growth and would help direct more public and private financing, from domestic and international sources, into the DRE sector. Specific examples developed further in this report
include:

• Rooftop Solar: A more holistic demand aggregation model integrated into the GoI’s Phase
II grid-connected RTS scheme would allow DISCOMs to get both a transaction fee for facilitating the installation as well as monthly fee for Operation & Maintenance (O&M),
such that billing/collection would better allow them to stay relevant and eliminate the
threat of disintermediation.

• Distributed Storage: Distributed energy-storage policy should be integrated with the Phase II RTS scheme. Instead of promoting a capital-subsidy based model, the government should create a more favorable environment for operational models with the involvement of DISCOMs.

• Smart Energy Management: Creating incentives for Internet of Things (IoT) based energy efficiency retrofits, that can attach to existing home circuits, will accelerate energy consumption optimization in households and small commercial establishments. This would not only help reduce energy bills and carbon footprint, but could strengthen overall grid resilience. For example, DISCOMs could move more quickly towards Time-of-Day billing as a part of their demand-side management.

• Electric Vehicle Charging Infrastructure: India’s EV-charging infrastructure should be treated as a public good. Policy should support a decentralized approach, with DISCOMs being the implementing agency for a franchise-based model. Allowing commercial establishments that produce excess solar power from RTS to set up retail charging points would be another step in the right direction.

• Solar Agricultural Pumps: The GoI’s KUSUM scheme currently has a centralized tendering process. Allowing state DISCOMs to partner with private installers at a local level should be considered. DISCOMs could facilitate commercial partnerships with solar pump installers and local farmer co-operatives. The DISCOM, through the installer, could pool the excess power generated from solar pumps into a single point of injection into the grid and pay power purchase costs, net of service fees, to farmer co-operatives.

• Solar Cold Storage: The GoI currently offers a 30% subsidy on solar cold storage installation under its broader rural livelihood subsidy scheme. However, considering the importance of cold storage in the agriculture supply chain, it is vital to create a separate solar cold storage program to bring down capital costs.

• Productive Use Appliances: It is imperative to shift the focus of grants from subsidizing
product purchases to providing project development support to entrepreneurs developing
the products. Equipment subsidies limit grant usage to the number of assets that it
can fund, whereas project development support allows entrepreneurs to both defray
technical assessment costs associated with commercial capital raising as well as develop
commercially scalable business models that reduce the cost of products for end-users.

FINANCING GAPS AND OPPORTUNITIES

The RTS and OGS markets are small and fragmented, largely reliant on philanthropy or subsidized private funding. There is currently limited interest from private commercial capital. Supported by stronger financial-sector policy and strategic public investment, the public, private, development and philanthropic sectors have a tremendous opportunity to work in coordination to open significant new DRE market opportunities for India.

MARKET POTENTIAL

The potential of distributed renewable energy in India is huge. In this section, we outline the
sub-segments that have the highest growth potential for meeting government targets for sustainable energy security in the coming years but have fallen short so far on this front.

ROOFTOP SOLAR
Adoption of rooftop solar by several small and medium industries can play a key role in decarbonizing India’s manufacturing supply chain.

Figure 1: Annual capacity addition

SOLAR AGRI-PUMPS
India has traditionally been an agricultural economy with over 160 million households dependent on agriculture for livelihood.6 Access to reliable water remains a challenge as
only ~50% of the agricultural land in India is currently under irrigation.7 This presents a unique market opportunity to provide solar-based irrigation solutions to around 80 million households in India. The Government of India (GoI), under its KUSUM scheme, has targeted a cumulative installed capacity of 1.75 million solar water pumps (around 6% of the total agricultural pumps in the country) by 2024.8 At the current average price of agricultural pumps of around INR 200,000 (USD 2,700), the estimated annual market size would be INR
10,000 crores (USD 1.5 Billion).

Figure 2: Solar water pump installed capacity

SOLAR COLD STORAGE
India’s weak agriculture supply chain results in significant loss in agricultural produce, leading to loss in income for farmers. The government has set itself a target of doubling farm income by 2024, for which having a robust supply cold storage infrastructure is essential.

Figure 3: Solar cold storage market size

DISTRIBUTED ENERGY STORAGE
Energy storage is a crucial tool for enabling the effective integration of renewable energy and
unlocking the benefits of local generation and a clean, resilient energy supply. The technology is valuable to grid operators around the world who must manage the variable generation of solar and wind energy. However, the development of advanced energy storage systems (ESS) has been highly concentrated in select markets, primarily in developed economies.

Figure 4: Lithium-ion battery costs

In India, factors like operational inefficiencies in the state distribution system, crosssubsidization of agricultural and residential customers, and infrastructure development costs to support government schemes (such as rural electrification) have created a huge revenue gap for DISCOMs, leading to an increase in tariffs for commercial and industrial customers.

Figure 5: Tariff structure in India

ELECTRIC VEHICLE CHARGING INFRASTRUCTURE
India has over 200 million registered vehicles – with the number of vehicles increasing by over 20% in just the last five years. This number is expected to go up significantly in the coming years as private motor vehicle penetration in India is only 4% as compared to about 80% in the United States and about 55% in the EU. By 2030, it is estimated that India will have 600 million vehicles. In 2017, electric vehicles (EVs) accounted for less than 0.1% of the total automotive sales in India. With technology development and favorable government policies leading to a fall in total cost of ownership, it is estimated that EVs have the potential to account for up to 30% of the total automotive sales in India by 2030.

LOW AGRICULTURAL FARM INCOMES FROM UNSUSTAINABLE FARMING PRACTICES
Rural farm incomes in India have traditionally lagged non-farm urban incomes by a considerable portion. This has been a major factor in the recurring cases of agrarian distress
in India leading to multiple bouts of farmer suicides. With agriculture becoming increasingly difficult to sustain livelihoods, an increasing number of farmers of newer generations are
migrating towards low-paid informal jobs in urban and semi-urban areas. This trend is likely
to have an adverse impact on the long-term quality of agriculture in India. With this in mind,
the government has created a policy target to double farm incomes by 2022.

WEAK AGRICULTURAL SUPPLY CHAIN
India’s weak agriculture supply chain results in a significant loss in agricultural produce, leading to a loss in income for farmers. The government has set itself a target of doubling farm income by 2022, for which having a robust cold storage infrastructure in the supply chain is essential.

DEVELOPING THE RURAL SERVICES ECONOMY
Access to a reliable grid-based electricity source remains a challenge for agriculture in India. As a result, mechanization in the farm and non-farm sectors remains low. The total addressable market for equipment such as reaper binders, knapsack sprayers, and rice transplanters has been estimated at around USD 40 billion. A multitude of activities exist in the ancillary (non-farm) agricultural sector that can benefit from reliable clean electricity: milk cooling, flour milling, sewing, weaving, tailoring, pottery, jewelry, poultry, vehicle repair, furniture manufacture, restaurants, retail, etc. The total addressable market for such activities has been estimated at around USD 15 billion.

Figure 6: Total addressable rural services market (USD Billion)

While India has reached 100% village electrification per government statistics, villages suffer from intermittent power. In addition, several village economic activities are located away from village electrified areas, increasing demand for solar-powered productive use appliances.

MANAGING PEAK DEMAND AND SUPPLY DEFICITS
The total household energy consumption was 275 TWh in 2018 and is expected to reach 640 TWh by 2030, a CAGR of 7.5%, due to increasing household electrical appliance use. In addition, commercial energy consumption is expected to increase from 95 TWh in 2018 to 200 TWh by 2022, a CAGR of 6.5%, due to increasing commercial building heating, ventilation, and air conditioning (HVAC) demand.

Figure 7: Energy consumption in India

ROOFTOP SOLAR
The GoI’s Phase II grid-connected RTS scheme, which provides a central role to DISCOMs for disbursement of central government subsidy, is a step in the right direction. However, the program only covers the residential segment and links the fiscal incentives for DISCOMs
to annual installed capacity, which would be difficult to achieve unless the C&I segment is
also considered. A more holistic demand aggregation model, which allows DISCOMs to get
both a transaction fee for facilitating the installation as well as monthly fee for Operation
& Maintenance (O&M) and billing/collection would better allow them to stay relevant and
eliminate the threat of dis-intermediation.

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Renewable energy finance: Sovereign guarantees

FFIDB PARA WEB_BAJA

RENEWABLE ENERGY FINANCE SOVEREIGN GUARANTEES

Less than two decades remain for countries around the world to make drastic cuts in
carbon-dioxide emissions. This is necessary to realise the goals of the Paris Agreement,
which calls for limiting the increase in average global temperature to well below 2 degrees
Celsius (°C) and ideally within 1.5 °C above preindustrial levels. The International Renewable
Energy Agency (IRENA) has estimated the total energy investments needed to fulfil the Paris
Agreement amount to USD 110 trillion by 2050, or USD 3.2 trillion per year.

RENEWABLE ENERGY INVESTMENT TRENDS

As renewables have become a compelling investment proposition, global investments in
new renewable power have grown from less than USD 50 billion per year in 2004 to around
USD 300 billion per year in recent years (Frankfurt School-UNEP Centre/BNEF, 2019), exceeding
investments in new fossil fuel power by a factor of three in 2018.

Another defining trend of renewable energy investments has been a geographic shift towards
emerging and developing markets, which have been attracting most of the renewable investments each year since 2015, accounting for 63% of 2018 renewable power investments
(Figure 1). Besides China, which attracted 33% of total global renewable energy investments in 2018,other top emerging markets over the past decade include India, Brazil, Mexico, South Africa and Chile (Frankfurt School-UNEP Centre/BNEF, 2019).Nevertheless, many developing and emerging countries in Africa, the Middle East, South-East Asia and South-East Europe still have a largely untapped renewables investment potential.

Figure 1 Global renewable energy investment (excl. large hydropower), in USD billion, by region, 2004-2018

In addition to the growing technological and geographical diversity, the renewable energy
investment landscape is also witnessing a proliferation of new business models and investment vehicles, which can activate different investors and finance all stages of a renewable asset’s life. Examples include the rise of the green bond market, growing interest in corporate procurement of renewable power and new business models for small-scale renewables such
as the pay-as-you-go model.

WHY SOVEREIGN GUARANTEES MATTER

Bringing a project to financial close requires all risks that the project bears to be allocated,
mitigated or transferred in a way that makes all stakeholders comfortable. This is no less true for renewable energy projects. Yet for projects in emerging countries, the main “residual” risks that few investors are able or willing to take are often related to the country itself. The buyer of the power may not be creditworthy, there is a risk that the legal and tax environment will change over time, or a new government may want to change the tariffs, among others. The “one size fits all” solution that most financial institutions asked for in the past to deal with country risks was a “sovereign guarantee”.

CURRENT ALTERNATIVES TO SOVEREIGN GUARANTEES

1.Guarantees are replaced by “letters of comfort” and “letters of support” The Ministry of Finance can still issue a document that does not have the same strength as a formal guarantee but that provides sufficient comfort to the stakeholders of the project. Some of these documents include strong commitments that can be legally enforced and are reviewed by the Attorney General, while others are more vague.

2. Use of the preferred creditor status of multilateral banks and insurers
Multilateral financial institutions that are majority owned by member countries and that have a
development role include multilateral banks (e.g., the World Bank, the Asian Development
Bank, the African Development Bank) and multilateral insurers (e.g., Multilateral Investment
Guarantee Agency (MIGA), Islamic Corporation for the Insurance of Investment and Export Credit (ICIEC), African Trade Insurance Agency (ATI)).

3. Put and call option agreement (PCOA)
Specifically, for PPAs, some countries have sought for a replacement of the traditional termination clauses that explicitly describe the responsibility of the government. Termination clauses come into effect if the IPP, the off-taker or the government fail to honour their obligations under the PPA. The party that is not responsible for the breach of contract can then terminate the contract and ask for compensation for the loss. In the case of a breach of contract by the off-taker, usually the national utility that is owned by the government,
then the government will have to pay the compensation. This is a contingent liability, and
potentially it accrues to the national debt.

4. Bilateral treaties
Bilateral treaties are agreements between two governments where the parties promise that
transactions made by a company from one country will not suffer from political risk events that are caused by the other government. Contrary to the system described under the PCS, the treaty covers all transactions and there is no notification to the government.

Figure 2 Structure of the ADB’s Pacific Renewable Energy Program

RECENT DEVELOPMENTS

1. Initiatives to improve the creditworthiness of the off-taker
In some countries, the fundamental problem is that the off-taker does not have a strong balance sheet for structural reasons. The logical solution is to improve the creditworthiness of the utility by recapitalising it, improving its management and operations, and ensuring that its revenues match its expenses and enable it to make investments in its infrastructure. This requires significant resources and a full commitment from the government. Several initiatives to achieve this exist in Africa, spearheaded by the World Bank, the African Development Bank and the Millennium Challenge Corporation.

2. Renovar
In this initiative of the Argentinian government, the payment obligations for all renewable energy PPAs are taken over by Renovar, a government institution, taking thus the risk away from the national utility. The payment obligations of Renovar are in turn guaranteed by MIGA, a part of the World Bank Group with an AAA rating. By removing the payment risk this way:
• The government effectively removes the credit risk;
• Transaction costs are reduced as all the IPPs are covered under one single contract between MIGA and Renovar.
This has helped the government of Argentina negotiate low feed-in tariffs.

3. The Regional Liquidity Support Facility (RLSF)
One of the major challenges for an IPP is to guarantee to its lender that even if the off-taker
delays payment, the loan (principal plus interest) will still be repaid on time. The related risk is named “liquidity risk”.

4. The Transparency Tool
This tool was developed as part of the RLSF. All the IPPs of a given country are invited to inform their invoices and their payment records to a webbased platform. The consolidated information is shared with all participating IPPs and with the off-taker. The tool also produces trendlines and other reports that make it possible to assess the experience of an IPP in comparison with other IPPs. The information can be made public from time to time. The objective is to demonstrate that, over time, the off-taker is a reliable payer and thus
there is no need for a guarantee.

5. Partial Risk Guarantees (PRG)
PRGs are on-demand guarantees that are issued by investment-grade multilateral institutions such as the World Bank and the African Development Bank. They can be triggered in case an event that is described in the guarantee letter takes place. In most cases the institution that issues the guarantee requests a back-to-back guarantee from the government (Ministry of Finance).

6. Africa GreenCo
Africa GreenCo is a private initiative that develops an alternative to the off-taker risk in countries covered by the Southern African Power Pool (SAPP). Its objective is to become the official off-taker of renewable energy IPPs. As an official off-taker, it would have the right to sell the power to other participants in the SAPP if the national utility fails to pay. Its creditworthiness would be provided through a mix of strong capitalisation and guarantees issued by investment-grade institutions. In such case, the non-payment becomes a commercial rather than a political risk for the IPP.

7. Push for PPAs in local currency
In many developing countries, the IPPs want to be paid in hard currency (usually US dollars or
euro), since their source of funds and their capital expenditure (“CAPEX”) are usually denominated in these currencies. On the other hand, the off-takers generate their revenue in domestic currency. The depreciation of the domestic currency can thus create a major problem for the off-taker and affect its ability to pay for the power that it purchases. If the PPA is expressed in hard currency but the actual payment is made in domestic currency, but at an agreed exchange rate, the supplier has the risk that it will not be able to make the conversion
in the hard currency. The additional risk is that the IPP will not be able or allowed to transfer its hard currency to a bank account outside the country.

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Renewable energy finance: Institutional capital

Investment in Renewable Energies Drops Globally | Financial Tribune

RENEWABLE ENERGY INVESTMENT TRENDS

As renewables have become a compelling investment proposition, global investments in
new renewable power have grown from less than USD 50 billion per year in 2004 to around
USD 300 billion per year in recent years (Frankfurt School-UNEP Centre/BNEF, 2019), exceeding
investments in new fossil fuel power by a factor of three in 2018.

Another defining trend of renewable energy investments has been a geographic shift towards
emerging and developing markets, which have been attracting most of the renewable investments each year since 2015, accounting for 63% of 2018 renewable power investments
(Figure 1). Besides China, which attracted 33% of total global renewable energy investments in 2018, other top emerging markets over the past decade include India, Brazil, Mexico, South Africa and Chile (Frankfurt School-UNEP Centre/BNEF, 2019). Nevertheless, many developing and emerging countries in Africa, the Middle East, South-East Asia and South-East Europe still have a largely untapped renewables investment potential.

Figure 1 Global renewable energy investment (excl. large hydropower), in USD billion, by region, 2004-2018

In addition to the growing technological and geographical diversity, the renewable energy
investment landscape is also witnessing a proliferation of new business models and investment vehicles, which can activate different investors and finance all stages of a renewable asset’s life. Examples include the rise of the green bond market, growing interest in corporate procurement of renewable power and new business models for small-scale renewables such as the pay-as-you-go model.

INSTITUTIONAL INVESTORS AND RENEWABLES

While the institutional investors analysed in IRENA’s study form a heterogenous group,
operating within different sector-specific and national circumstances, they also face several ommon trends.

Growing assets Their global assets are large and growing. While a broader group including asset managers commands assets of well over USD 100 trillion, the group analysed in IRENA’s report (pension plans, insurance companies, sovereign wealth funds, foundations and endowments) manages around USD 85 trillion (Figure 2), which has been growing at an annual rate of around 4-7% over the past decade.

Figure 2 Assets under management of the institutional investors, USD trillion, 2018-2019 average

Regional shift Markedly faster growth is occurring in emerging and developing markets. This is due to their growing economies, populations and expansion of pension plan and insurance coverage. Double-digit growth rates have been recorded for pension plans and insurance companies in several countries in Africa, Asia and Latin America. Ten out of 20 African sovereign wealth funds were created since 2010 (Quantum Global, 2017). Such local capital can help bridge local infrastructure funding gaps and support long-term sustainable development.

Figure 3 Number of institutional investors with investments in renewable energy
(projects and/or renewable-focused funds), 1990 to Q2 2019

From the sample of over 5 800 institutional investors and their investments for the past two
decades, 37% of institutional investors have made infrastructure investments, 25% have invested in energy-related funds, while 20% have invested in renewable energy-focused funds and only around 1% have made investments directly in renewable energy projects (Figure 3).

Size effect Institutional investors with renewable energy assets are larger than average. Average assets under management for such investors total USD 30 billion, more than double the average assets under management for institutional investors in the whole sample (USD 12 billion). Furthermore, institutional investors with only direct renewable investments are larger than institutional investors with only indirect investments (USD 34 billion of assets under management versus USD 24 billion). As well, the average deal size increases from USD 199 million to USD 434 million when institutional investors are involved. IRENA’s discussions with institutional investors support hypotheses that larger investors have greater internal capacities for investments in relatively new asset classes like renewables, and that larger transactions are more likely to attract institutional investors as bigger ticket sizes lower the per-unit transaction costs.

Investment amount The number of direct renewable energy projects involving institutional investors has increased over time, from as few as 3 recorded transactions in 2009, to 73 in 2018 and 38 for the first two quarters of 2019 (Figure 4). Over the past decade, institutional investors were involved in 231 renewable energy direct financing transactions. However, this represents only 1.8% of all renewable energy projects in the dataset analysed over the same period. The total annual amount financed by institutional investors was nearly USD 6 billion in each of 2018 and 2017 (CPI, 2019). While this marks an increase from around USD 2 billion invested in each of 2016 and 2015, it represents only around 2% of the total renewable project
investments in 2018.

Figure 4 Number of renewable energy projects that involved institutional investors, by technology,
2008 to Q2 2019

Technology preference Around 81% of all renewable power deals in which institutional investors took part over the past decade were in wind and solar technologies. This reflects the global technological trend in the renewable power sector as a whole. However, compared to total renewable power investments over the past decade, institutional investors have favoured wind more strongly. For the 2009-2018 period, global investments in solar projects were around 50% of total renewable energy investments, followed by wind which accounted for
39% (Frankfurt School-UNEP Centre/BNEF, 2019). For the same period, considering only renewable project investments involving institutional investors, wind accounted for 45% and solar for 24% of all transactions. This is most likely because wind is a more established renewable technology with larger transaction sizes that attract institutional investors.
In the sample analysed, the average transaction size for a wind project was USD 211 million, compared to USD 124 million for solar.

Investment stage preference Institutional investors exhibit a strong preference for already-operating assets, which help them avoid early-stage risks associated with the structuring and construction stages. Over 75% of all renewable energy deals involving institutional investors during the 2009 to Q2 2019 period were secondary-stage transactions, i.e., investments in already operating assets not requiring further funding, while around 22% were for the construction of new assets (i.e., greenfield stage), and a small portion went to brownfield projects (already operating assets that require improvement or expansion). Investment
vehicles that help such investors channel their assets into already operating projects are therefore important, as is building internal capacities for earlier-stage investments.

Institutional investors could play a more active role in renewable-sector investments and
become a significant contributor to the global capital shift towards low-carbon solutions. Such
a shift will, however, require combined efforts on multiple fronts with active engagement from all stakeholders: policy makers, institutional investors, providers of public capital, capital markets and others.

Figure 5 Recommended actions to scale up institutional investments in renewable energy

OPPORTUNITIES FOR ENGAGEMENT

As the only international organisation dedicated solely to renewable energy, IRENA is uniquely positioned to support countries in their transition to a sustainable energy future. IRENA provides analytical guidance and develops solutions for market opportunities, successful business models and financial instruments; supports renewable energy projects throughout
their life cycle; leads the global discourse; connects key stakeholders; and provides a global forum for the exchange of best practices.

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Reduce: Non-bio renewables

Biobased Products for a Sustainable (Bio)economy | edX

Introduction Climate change has become one of the greatest threats of this century to environmental, as well as global, security, with adverse impacts on health, wealth and political stability. Over the past decade, energy-related CO2 emissions have increased by 1% per year on average, despite levelling off periodically. If historical trends continue, energy-related emissions will increase by a compound annual rate of 0.7% per year to 43 gigatonnes (Gt) by 2050 (up from 34 Gt in 2019), resulting in a likely temperature rise of 3°C or more in the second half of this century. Governments’ current and planned policies would result in a levelling of emissions, with emissions in 2050 similar to those today, but this would still cause a temperature rise of about 2.5°C. The Paris Agreement establishes a goal to limit the increase of global temperature to “well below” 2°C, and ideally to 1.5°C, compared to pre-industrial levels, by this century. To realise this climate target, a profound transformation of the global energy landscape is essential.

Current Status

This section will show how renewable energy is a proven and available technology by providing the latest figures, trends and market developments in renewable energy deployment worldwide. The strong business case for renewables is demonstrated by their cost, performance and deployment evolution, especially when considering trends in solar PV, wind and other renewable power generation options, along with the growing viability of energy storage technologies. The current innovation landscape for enabling technologies, business models and system operation will also be outlined and discussed.

Renewable power generation continues to grow in 2020, despite the COVID-19 pandemic, but new capacity additions in 2020 will be lower than the new record previously anticipated. Nonetheless, renewables steadily increasing competitiveness, along with their modularity, rapid scalability and job creation potential, make them highly attractive as countries and communities evaluate economic stimulus options.

Figure 1. Evolution of LCOE costs for solar PV and wind onshore (2010- 2019)

The share of renewable energy in electricity generation has been increasing steadily in the past years and renewable power technologies are now dominating the global market for new generation capacity. From 2010 to 2018, the renewable electricity generation share increased
from around 20% to nearly 26%, or 18% to 23% without considering bioenergy.

Figure 2. Evolution of renewable energy in the power sector (2010- 2017/2018/2019)

Dramatic shifts are taking place in the way that energy systems operate, driven by increased
digitalisation, the decentralisation and democratisation of power generation, and the growing
electrification of end-use sectors. Indeed, the main driver for the energy transformation is increased use of electricity, such as in the growing electric mobility revolution. Electric vehicle
(EV) sales (both battery-electric and plug-in hybrids) reached 2.2 million units in 2019 (InsideEVs, 2020a), continuing the growth from the previous year.

Renewable technology and carbon reduction outlook

Renewable energy, combined with intensified electrification, is key for the achievement of the Paris Agreement goals. To help enable the necessary transformation of the global energy sector, IRENA has developed an extensive and data-rich energy scenario database and analytical framework, which highlights immediately deployable, cost-effective options for countries to fulfil climate commitments and assesses the projected impacts of policy and technology change.

However, the reduction of carbon emissions is not the only reason why the world should embrace the energy transformation. Figure 4 (below) outlines other important drivers.

Figure 4. Key drivers for the energy transformation

To set the world on a pathway towards meeting the aims of the Paris Agreement, energyrelated carbon dioxide (CO2 ) emissions need to be reduced by a minimum of 3.8% per
year from now until 2050, with continued reductions thereafter.

Figure 5 shows the possible paths of annual energy-related CO2 emissions and reductions as
per three scenarios: the Baseline Energy Scenario (indicated by the orange line); the Planned
Energy Scenario (indicated by the yellow line); and IRENA’s energy transformation pathway, the
Transforming Energy Scenario (indicated by the blue line).

Figure 5. Annual energy-related CO2
emissions and mitigation contributions by technology in the Baseline
Energy Scenario, the Planned Energy Scenario and the Transforming Energy Scenario (2010-2050)

In the Baseline Energy Scenario, energy-related emissions would to increase at a compound
annual rate of 0.7% per year to 43 gigatonnes (Gt) by 2050 (up from 34 Gt in 2019), resulting
in a likely temperature rise of 3°C or more by the end of the century. If the plans and pledges of countries are met as reflected in the Planned Energy Scenario, then energy-related CO2
emissions would increase each year until 2030, before dipping slightly by 2050 to just below today’s level.

Global pathway and decarbonising with renewables
Under current and planned policies in the Planned Energy Scenario, the total share of non-biomass renewable energy in the total primary energy supply (TPES) would only increase from around 5% to 17%, while under the Transforming Energy Scenario it increases to 42% (Figure 6). Renewable energy use in absolute terms, excluding biomass, would increase from 25 exajoules (EJ) in 2017 to 225 EJ in 2050 in the Transforming Energy Scenario. TPES would also fall slightly below 2017 levels, despite significant population and economic growth.

Figure 6. The global energy supply must become more efficient and more renewable

Scaling up electricity from renewables is crucial for the decarbonisation of the world’s
energy system. The most important synergy of the global energy transformation comes from
the combination of increasing low-cost renewable power technologies and the wider adoption of electricity for end-use applications in transport and heat and hydrogen production. To deliver the energy transition at the pace and scale needed would require almost complete decarbonisation of the electricity sector by 2050.

For power generation, solar PV and wind energy would lead the way. Wind power would
supply more than one-third of total electricity demand. Solar PV power would follow, supplying 25% of total electricity demand (Figure 7), which would represent more than a 10-fold rise in solar PV’s share of the generation mix by 2050 compared to 2017 levels. To achieve that generation mix, much greater capacity expansion would be needed by 2050 for solar PV (8 519 GW) than for wind (6 044 GW).

Figure 7. Breakdown of electricity generation and total installed capacity by source, 2017-2050

G20 overview The Group of Twenty (G20) members account for 85% of the global economy, two-thirds of the global population and almost 80% of global energy consumption. The energy mix in G20 economies is quite varied; however, most countries currently rely on a high share of fossil fuels in their total energy supply and thus are responsible for more than 80% of global CO2 emissions. Yet G20 economies have also become leaders in fostering cleaner energy systems, and their energy transition will shape global energy markets and determine both emissions and sustainable pathways globally.

Table 2 presents the evolution of key energy sector indicators in the G20 from today’s levels in the Transforming Energy Scenario (to 2030, 2040 and 2050). The Transforming Energy Scenario
leads to lower levels of supply and consumption of energy in absolute terms. By 2050, 51% of final energy consumption is electrified, with the highest share in buildings at 65%, followed by transport at 45% and industry at 44%. Renewable energy would have a prominent role in the electricity mix, with solar PV and wind (onshore and offshore) leading the way in absolute terms.

Table 2: Evolution of key energy indicators in G20 for 2017 and for the Transforming Energy Scenario in
2030-2040 and 2050

Socio-economic footprint of the G20 energy transition

A true and complete energy transition includes both the energy transition and the socio-economic system transition, and the linkages between them. Therefore, a wider picture is needed that views energy and the economy as part of a holistic system.

The approach analyses variables such as GDP, employment and welfare (Figure 17). The results from the socioeconomic footprint analysis of the Transforming Energy Scenario globally show an additional net 15 million jobs and a 13.5% improvement in welfare by 2050, as well as an annual average boost of 2% in GDP between 2019 and 2050 compared to the Planned Energy Scenario.

Figure 17. Estimating the socio-economic footprint of transition roadmaps

Energy sector and renewable energy jobs in the G20
The energy transition implies deep changes in the energy sector, with strong implications for
the evolution of jobs. While some technologies experience significant growth (e.g. renewable
generation, energy efficiency and energy flexibility), others would be gradually phased out (e.g.
fossil fuels), and all of this happens simultaneously with the evolution of energy demand.

Figure 18 presents the evolution of energy sector jobs in the G20 for both the Planned Energy
Scenario and the Transforming Energy Scenario, by technologies. The Transforming Energy
Scenario leads to a higher number of overall energy sector jobs than the PES, as declines in the
number of fossil fuel jobs are more than offset by increases in jobs in renewable energy, energy efficiency and energy flexibility. By 2050, nearly 71 million people would be employed in the energy sector in the Transforming Energy Scenario, 46% in renewable energy, 25% in energy efficiency and 15% in energy flexibility. About 13% of energy jobs would still be in fossil fuels.

Figure 18. Evolution of energy sector jobs, by technology, under the Planned Energy Scenario and the
Transforming Energy Scenario from 2017 to 2030 and 2050

Gross domestic product in G20
Figure 23 show the yearly evolution of the difference in GDP between the Planned Energy
Scenario and the Transforming Energy Scenario up to 2050, as well as the impact from
the different drivers of the GDP difference. The energy transition brings about a significant
improvement in GDP, with the increase rising to 3% before 2040 and remaining there until 2050.

Figure 23. Dynamic evolution of the drivers for GDP creation from the Planned Energy Scenario and the
Transforming Energy Scenario across the 2019 – 2050 period

Welfare in the G20
The sections above discussed the employment implications of the energy transition. Beyond
employment, other dimensions affect welfare. To capture a more holistic picture of the energy
transition impact, IRENA uses a welfare index with three dimensions (economic, social and
environmental) and two subdimensions in each. Figure 25 presents the results of the welfare index for the G20 in the years 2030 and 2050. The welfare improvement of the Transforming Energy Scenario over the Planned Energy Scenario is very important, reaching 14% in 2050. Social and environmental dimensions, and specifically the health and GHG emissions subdimensions, dominate the overall welfare index results in the G20.

Figure 25. Evolution of the Welfare index for the G20 under the Transforming Energy Scenario

Barriers to the deployment of renewable energy

Despite the powerful factors driving the global uptake of renewable energy, multiple barriers inhibit further uptake in developed and developing markets. These vary based on specific markets and renewable energy technologies. This section outlines the some of the main barriers globally.

Enabling policies

Five years after the historic signing of the Paris Agreement, countries around the world
are struggling to translate their emissions reduction pledges into concrete actions to fight
climate change. IRENA estimates that if all national renewable energy targets in the first round
of Nationally Determined Contributions (NDCs) are implemented, around 3.2 TW of renewable
power capacity would be installed globally by 2030, 59% short of the capacity needed according to IRENA’s Transforming Energy Scenario. In the G20, around 2.8 TW of renewable power capacity would be installed by 2030, 60% short of the 7 TW envisioned in the Transforming Energy Scenario (IRENA, 2019h). Considerable opportunity exists to raise ambitions in a cost-effective way through enhanced renewable energy targets.

price was USD 48/MWh. G20 countries have been leading these trends (Figure 26), with record
low prices achieved on many occasions in Brazil, Mexico and Saudi Arabia.

Figure 26. Weighted average prices of energy resulting from solar and wind auctions, globally and in G20
countries, and capacity awarded each year, 2011-2018

Measures to improve power system flexibility are needed to enable the integration of
higher shares of VRE. Investment must be steered into innovations in all flexible resources
(storage, demand-side management, interconnectors and dispatchable power plants), market
design and system operations.

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SOLAR SUPPLY CHAIN TRACEABILITY PROTOCOL 1.0 INDUSTRY GUIDANCE

Solar manufacturers, utilities and developers back anti-forced labour  pledge - PV Tech

INTRODUCTION
Transparency of supply chains is paramount. Equipment purchasers, electricity end-users, and other stakeholders demand transparency for reasons ranging from sustainability to corporate social responsibility to import compliance. In this environment, manufacturers must have the proper systems in place to meet stakeholder needs and build trust. To assist the industry, SEIA, with the support of Clean Energy Associates (CEA) and Senergy Technical Services (STS), has developed this Solar Supply Chain Traceability Protocol 1.0 (Protocol) to help manufacturers and importers demonstrate the provenance of their products by developing and implementing a traceability program consistent with the general principles herein.

SCOPE
The Protocol is intended to have universal application across product lines intended for export to the U.S. market.Key adopters of the Protocol will include:
• Equipment manufacturers; and
• U.S. importers.
While the Protocol focuses on the provenance of material inputs, it also recognizes the importance of independent, third-party audits and a strong corporate social responsibility and import compliance platform. In assessing conformance, auditors shall apply a holistic approach which recognizes an organization’s unique business processes. No single factor will be dispositive.

TERMS AND DEFINITIONS
Accountability – State of being answerable for decisions and activities to the organization’s governing bodies, legal authorities, and, more broadly, its stakeholders. Documentation – Documents and attestations sufficient to generally establish place and date of manufacture
and/or transfer of goods. Due diligence – A comprehensive, proactive process to investigate, appraise, or evaluate a product or organization. Due diligence is conducted to identify the actual and potential consequences of an organization’s decisions and activities over the entire life cycle of a project or organizational activity, with the aim of avoiding and mitigating negative impacts.

DRIVERS FOR TRANSPARENCY IN THE SUPPLY CHAIN GENERAL
The motivations of organizations for practicing transparency in the supply chain differ depending on the type of organization and the context in which they operate. Drivers for transparency should be analyzed to help define the transparency objectives and goals for the supply chain and to aid internal communication. This section provides examples of drivers for the implementation of a transparency system in the supply chain.

MANAGEMENT OF TRANSPARENCY IN THE SUPPLY CHAIN RISK APPROACH
One key to establishing a robust supply chain transparency system resides in addressing risk – both internal and external. Risk management should therefore be integrated in the decisional and operational activities and conducted in a dynamic, iterative, and responsive manner.

The organization should identify, prioritize, and address risks to increase its resilience to events which can impede product traceability. This includes considering how suppliers are capable of meeting traceability requirements such as monitoring and auditing. It is recommended that the organization conduct an initial review to create a baseline of the risks and opportunities in relation with its products’ traceability.

INTEGRATION OF TRANSPARENCY INTO MANAGEMENT SYSTEMS CONTEXT
The organization should consider product traceability as a priority issue, internally and externally, in its contextual analysis. Stakeholders should be identified and engaged, and information relevant to material provenance monitored and reviewed.

INTEGRATION OF TRANSPARENCY INTO OPERATIONAL PROCESSES PRODUCT DEVELOPMENT
The organization should factor traceability considerations into the product design process.

SUPPLY CHAIN MAPPING
The organization should be able to present a description of the entities involved in creating the product that is being imported. This description can include an illustration of the links in the supply chain in a step-by-step flow from raw materials to finished goods, i.e., supply chain map. While the map can take many forms, the essential elements of a map are illustrated here:

The map should identify individual steps in the process and each step should include information about that step’s entity, such as the item being produced, a description of the overall manufacturing process(es) being employed, the name of the producer, and the location of production. In the case of multiple suppliers of the same item, the map would indicate multiple entities. In the event there are multiple production locations for an entity that are in the supply chain for the final product, the relevant locations should be identified.

Each time there is a transaction between steps in the supply chain, the importer should disclose the nature of the document that codifies the transaction, i.e., a purchase order, supply contract, etc., as well as identify the business unit of the individual who places the order.
Complex products and products with many components or suppliers can lead to complex supply chain maps. These can be simplified by addressing raw materials or intermediate items that are of particular importance, either because of location, cost, uniqueness of the time, or other factors. A more detailed map is illustrated here:

If wafers from different logs are combined, then a new and unique identifier should be assigned to the mixed batch and the provenance of the wafers in the batch should be linked to the batch identifier.

In short, for a pallet of wafers, perhaps identified only by a unique pallet number, the purchaser of the wafers should be able to trace the provenance back to a specific ingot or ingots.

RELEASE OF PRODUCTS
The organization should integrate traceability and security requirements into its product releasing process. The release process should include, as a minimum:
• Availability of traceability information for the products to be shipped;
• Correct identification of the product;
• Where applicable, serialization of the materials;
• Integrity of the products packaging;
• Presence and condition of security elements, including where applicable, transportation seals; and
• Documentary review of logistic documentation including bill of lading and transportation information.
The organization should have documented procedures to prevent shipment of products that have not passed through the release process. Releasing process shall be conducted by qualified personnel having received supply chain security training.

SOLAR WAFER
Poly-Si inputs for production of monocrystalline silicon wafers destined for use in solar modules should be delivered in designated and uniquely identifiable shipping units, e.g., lot or batch number. The logistics documents associated with each shipping unit should preserve the upstream provenance of the input material and that information should be linked to the output product.

The manufacturing processes of solar wafers should include, when necessary, rigorous controls to prevent mixing of input poly-Si from different sources. Additionally, there may need to be rigorous controls to prevent mixing of intermediate products on the production floor. Each intermediate product generated during solar wafer production should be tracked with a Manufacturing Execution System (MES) that can link each intermediate product to its parent product and resulting product(s).

Solar wafer output material should be boxed in defined and easy to handle amounts, e.g., 100 wafers per box. Each shipping unit above should have a unique serial number that can be used to trace the input poly-Si material.

Where material inputs from different sources are mixed or blended together, the manufacturing process should include rigorous controls to maintain provenance, e.g., the source of both inputs travels across the supply chain. Each intermediate product generated during solar cell production, should be tracked with a Manufacturing Execution System (MES) that can link each intermediate product to its parent product and resulting product.

Solar cell output material should be boxed in defined and easy to handle amounts, e.g., 100 wafers per box. Boxes of cell may be combined into larger boxes which are then combined on a pallet. Each shipping unit should have a unique identifier, e.g., unique box number, that can be used to trace the input solar wafer material. When necessary, manufacturers should also maintain an auditable process for keeping material from different sources physically separated at each intermediate step in the solar cell manufacturing process.

SOLAR MODULE
Solar cell inputs for production of solar modules should be delivered in designated, serialized shipping units. The logistics documents associated with each shipping unit should preserve the upstream provenance of the input material and that information should be linked to the output product.

The manufacturing processes of solar modules should include rigorous controls to prevent mixing of input cells from different sources. Additionally, there must be rigorous controls to prevent mixing of intermediate products on the production floor. Each intermediate product generated during solar module production should be tracked with a Manufacturing Execution System (MES) that can link each intermediate product to its parent product(s) and resulting product(s).

Solar module outputs should be palletized in defined amounts, e.g., 20-30 modules per pallet. Each pallet should have a unique serial number that can be used to trace the input solar cell material.

ANNEX B: GUIDANCE ON RISK MANAGEMENT RISK FACTORS
Supply chain risks can be associated with the following:

RISK MANAGEMENT PROCESS
Risk management processes shall follow an improvement cycle based on the inputs gathered.

RISK IDENTIFICATION
In the risk identification phase, the organization should create an objective list of the risks taking into consideration a variety of factors, such as the nature of risk and changes in risk profile. The organization may use different techniques such as interviews, surveys, and auditing to increase reliability in the characterizations of the risk.

IMPLEMENTATION OF THE DUE DILIGENCE PROGRAM
OVERVIEW OF DUE DILIGENCE PROCESS
The implementation of the due diligence process will consist of the repetition of individual due diligence activities, combined and summarized to provide an overview of the whole supply chain in the scope of the due diligence program.

INITIATING DUE DILIGENCE ACTIVITY
The audit team should first establish a dialogue with the organization’s compliance department and confirm communication channels, including:
• Confirm authority to conduct due diligence activity;
• Provide relevant information on the due diligence process (e.g., scope, criteria, methods, teams, schedule);
• Request access to relevant information to conduct due diligence activity;
• Determine applicable statutory and regulatory requirements;
• Confirm management and treatment of information, especially the management of confidentiality;
• Confirm arrangements including schedule, access, health and safety, and security;
• Confirm attendance of observers where applicable;
• Determine relevant areas of interest or concern with the organization subjected to due diligence activity

NONCONFORMITY MANAGEMENT
In this section, nonconformity refers to findings identified during the due diligence process or to a nonconformity arising from the process itself. Nonconformity arising from the process itself may include:
• Failure to perform due diligence as agreed;
• Unresolved diverging opinions on the outcome of the due diligence process;
• Reported Impartiality or ethical issues occurring during due diligence;
• Competences issues identified during the diligence process; and • Breach of confidentiality or information security occurring the due diligence process.
The organization should establish a process, including reporting, investigating, and taking actions to determine and manage nonconformities. When a nonconformity occurs during due diligence, the organization should as applicable:
• React timely to control the nonconformity;
• Take actions as applicable to correct the nonconformity and deal with the consequence; and
• Take actions to prevent reoccurrence of the nonconformity.

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